Page 1542 – RTO Insider

March 24, 2017

ISO-NE Nixes Keene Road Tx Upgrade

By Michael Kuser

WESTBOROUGH, Mass. — Transmission developers will have to wait a bit longer for ISO-NE’s first competitive project.

The RTO told stakeholders Wednesday that it will not issue a request for proposals for the Keene Road market efficiency transmission upgrade because the cost would be greater than the production savings. The grid operator had explored the project as a way to release pent-up wind resources in Maine.

Rollins Wind Farm in Maine | *Reed & Reed, Inc.*

Director of Transmission Planning Brent Oberlin presented his staff’s analysis to the Planning Advisory Committee on March 22, confirming preliminary results released in December. (See ISO-NE Study Sees Little Savings from Keene Road Tx Upgrade.)

The study showed increasing the Keene Road export limit from 165 MW to 195 MW would save $1.37 million in production costs annually over a 10-year period. Raising the interface export capacity beyond 195 MW would result in very small additional savings. ISO-NE estimated a total project cost of $7 million to $10.4 million.

Detail of Keene Road Constrained Area | *ISO-NE*

The upgrade would have been eligible for competitive bidding under FERC Order 1000. ISO-NE has yet to implement a request for proposals under the order.

The New England States Committee on Electricity (NESCOE) said the upgrade isn’t worth the cost to consumers.

“First, consumers would fund ISO-NE’s first-time work to implement an RFP and evaluation process,” NESCOE said in comments filed with the RTO last month. “Second, as required by the Tariff, consumers would also have to pay for the incumbent transmission owner to develop a backstop solution. Those unavoidable costs have to be considered in the context of a very small project for which there is no present indication that an economic solution exists.”

Aleks Mitreski of Brookfield Renewable filed comments saying his company “strongly supports” the project. “In addition to production savings, there would be significant added benefits in the added production of non-emitting [megawatt-hours] that would contribute toward meeting state policy goals and GWSA (Global Warming Solutions Act) targets,” he wrote.

Jeff Fenn of SGC Engineering, representing Emera Maine, also questioned Oberlin. “It’s not entirely true that no one has come forward with a solution” for the Keane Road bottleneck, he said.

The Keene Road interface is the 115-kV system that is left after the loss of the Keene Road 345/115-kV autotransformer, Fenn told RTO Insider after the meeting. The interface can be overloaded by the locally connected 115-kV generation, causing a voltage violation upon loss of the autotransformer.

Fenn said the problem could be solved by eliminating some of the generation post-contingency.

One method would be relocating one of the generator leads such that it was lost with the loss of the autotransformer. An alternative would be a generation rejection special protection scheme.

Fenn said either solution would cost less than $500,000, “therefore well within the payback as defined by the ISO economic study. In addition to this, it is probable that one of the generators in the area would be willing to fund the change as the benefit to them would provide a rapid payback.”

However, Fenn said the RTO “determined that the line relocation smelled too much like an SPS, and as such was not allowed to be considered. They also refused to consider the SPS alone as a solution.”

March 24, 2017

Anemic Loads, Plentiful DR Boost MISO Summer Outlook

NEW ORLEANS — MISO expects a 19.2% planning reserve margin this summer, well above its 15.8% requirement, and a percentage point above its projection last year, despite predictions of higher-than-normal temperatures.

The figure is also higher than the prediction of 17.4% in the RTO’s resource adequacy survey with the Organization of MISO States. The RTO said the difference was the result of negative load growth and more demand response resources.

“We’re seeing a decline in load forecasts and an increase in demand response,” explained MISO Vice President of System Operations Todd Ramey at the March 21 Markets Committee of the Board of Directors meeting.

Independent Market Monitor David Patton said his monitoring staff has calculated a similar percentage.

The RTO relied on data from the National Oceanic and Atmospheric Administration to calculate summer readiness; the agency forecasts higher-than-average summer temperatures in the footprint, with MISO South experiencing the most significant temperature spikes.

miso reserve margin demand response — | *NOAA*

Based on the forecast, the RTO expects a 125.1-GW peak demand with 149.1 GW of supply on hand to meet it. Last year, the RTO anticipated a 125.9-GW peak demand and said it had 148.8 GW at the ready for an 18.2% reserve margin. The RTO’s 24 GW worth of reserves are higher than last year’s 23 GW, and beats the requirement by 4.2 GW.

MISO will reveal final reserve margin numbers at a summer readiness workshop sometime in May.

— Amanda Durish Cook

March 23, 2017

FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible

FERC staff have greenlit — perhaps temporarily — PJM’s proposed Tariff revisions to allow increased participation from seasonal resources just in time for the RTO’s Base Residual Auction in May (ER17-367). The order remains subject to refund and further FERC action.

The proposals had been on a 60-day clock that would have allowed them to go into effect on March 24, but staff’s order keeps the door open for additional commission review once it regains a quorum of commissioners. (See “Loss of Quorum Means Filings to Become Effective Unless FERC Staff Acts,” PJM Market Implementation Committee Briefs.)

ferc pjm seasonal resources — Mehoopany Wind Farm | *Old Dominion Electric Cooperative*

The changes relax current rules prohibiting seasonal resources from aggregating across locational deliverability areas. The proposal also provides for additional winter capacity interconnection rights (CIRs) and modifies rules for measuring demand response performance in the winter.

PJM sparked controversy about a highly debated issue among stakeholders when it unilaterally filed the revisions with FERC in October under Section 205 of the Federal Power Act. The commission issued a deficiency notice in December, which PJM replied to in January. (See FERC Wants More Detail on PJM’s Seasonal Capacity Plan.)

While the order notes that protesters argued that PJM’s proposal was “an insufficient solution to the larger problem of the costly and inefficient nature of eliminating stand-alone sub-annual resources,” it nonetheless granted the effective dates PJM proposed: Jan. 19 for winter CIRs and June 1 for DR revisions. Requests for rehearing must be filed within 30 days.

– Rory D. Sweeney

March 22, 2017

PJM Board Disputes UTC Trader’s Accusations

By Rory D. Sweeney

The PJM Board of Managers responded on Monday to accusations leveled by XO Energy in February, defending the grid operator’s practices and denying the up-to-congestion trader’s request that the board disregard rule changes on uplift recently endorsed by stakeholders.

In a long and strongly worded letter to the board, XO President Shawn Sheehan accused PJM staff of having bias against financial-sector stakeholders and actively working to undermine their interests. He was specifically concerned with how the process played out in the Energy Market Uplift Senior Task Force, which recently proposed a phased response to uplift issues. Those proposals were eventually endorsed at both the Markets and Reliability and Members committees. XO had asked that the board not act on the endorsements pending the outcome of FERC’s recent Notice of Proposed Rulemaking on uplift issues. (See UTC Trader Displeased with PJM’s Handling of Uplift Rule Changes.)

PJM CEO and board member Andy Ott responded to Sheehan’s claims in a much more reserved tone March 20, suggesting that Sheehan could meet with Dave Anders, the RTO’s director of stakeholder affairs, to discuss his concerns further. Ott defended the RTO’s stakeholder procedures, noting that it provided technical experts that offered “a significant amount of objective technical analysis” throughout the yearslong development of proposals from the task force.

“PJM’s role is to ensure the market remains efficient and competitive, and to provide analysis and justification if they believe certain market inefficiencies should be addressed,” Ott wrote. “I appreciate that some PJM stakeholders disagree with PJM’s conclusions in this regard, but such disagreements do not make PJM biased or negative toward any particular stakeholder group.”

Sheehan had suggested that PJM staff pushed stakeholders into approving the proposals and didn’t provide enough opportunity for engagement, but Ott noted that the process had been going on for more than three years.

“Clearly, abundant opportunity has been afforded to all stakeholders, including the financial community, to express views, persuade others and offer alternatives,” he wrote. “I can find no basis to adopt the extraordinary remedy you have suggested, which would table and disregard the expressed preferences of a very sizeable majority of the PJM members.”

The MRC and MC endorsed proposals for phases 1 and 2 of the uplift response. Proposals for a third phase are still being discussed at the task force level and haven’t been brought for discussion at any of the standing committees.

March 22, 2017

CAISO to File ‘Expedited’ Black Start Plan in May

By Robert Mullin

CAISO staff expect to submit a proposed black start procurement proposal to the Board of Governors in May, officials said Tuesday.

The ISO launched an accelerated procurement effort in January after identifying the need for additional black start resources in the transmission-constrained San Francisco Bay Area. (See CAISO Kicks Off Effort to Procure Black Start Resources.)

CAISO kicked off the black start procurement initiative to obtain resources equipped to restore the transmission system in the San Francisco area in the event of a blackout. | *SF Travel*

“I’m not expecting [that] we’re going to have significant Tariff changes for purposes of this initiative,” Andrew Ulmer, CAISO director of federal regulatory affairs, said during a March 21 call to discuss a draft final proposal that deviated little from the approach laid out in the initial proposal. (See CAISO Proposes TO-focused Black Start Procurement.)

Ulmer added that the ISO hoped to make draft Tariff language changes available to stakeholders ahead of the board vote.

The black start initiative represents the second phase of a 2013 undertaking to address NERC reliability standard EOP-005-2, which required transmission operators to draw up plans for system restoration in the event of widespread blackouts.

The ISO’s plan envisions the significant involvement of an affected transmission owner in selecting a black start resource, both in drawing up technical specifications and vetting proposals from those resources that bid into the solicitation.

Based on stakeholder feedback, CAISO settled on a cost-of-service approach to compensating the resource, rather than providing a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.

The payment would allow for recovery of capital and fixed operations and maintenance costs plus a “reasonable margin” for the resource owner, according to Scott Vaughan, lead grid assets manager at the ISO.

The proposal calls a resource to be contracted under a three-party agreement between the ISO, the local TO and the resource’s owner.

Paul Nelson, electricity market design manager at Southern California Edison, sought more details about the nature of the agreement — specifically the extent of the TO’s responsibility.

Ulmer explained that CAISO expects that any black start resource procured under the process would not only become part of the ISO’s system restoration plan but that of the TO as well.

“It makes sense to us to have a three-party agreement with ISO, the black start resource and the participating transmission owner … ensuring we have evidence that we secured the capability for the [NERC] reliability standards.”

“So … there’s three roles — the ISO, the black start resource and the transmission — and all three in conjunction need to provide certain services and responsibilities, and the contract will lay out what those are and who’s responsible for the roles and responsibilities and the costs,” Nelson offered.

“Yes, that’s correct,” responded Ulmer, adding that in April, CAISO intends to release a sample contract for stakeholder review.

CAISO also plans next month to publish draft technical specifications for black start resources, followed by a stakeholder meeting on the subject during the second half of May. During the first half of June, the ISO expects to issue a request for proposals for resources in the San Francisco area.

Stakeholders should submit comments on the black start draft final proposal to the ISO by April 4.

March 21, 2017

Gov.’s Support Puts Md. on Track for Fracking Ban

By Rory D. Sweeney

Maryland Gov. Larry Hogan said Friday he will support a ban on fracking, potentially making the state among the first to enact a statutory ban on the oil and gas extraction method.

In making the announcement, Hogan, a Republican, departed from his previous stance that he would support the practice and that he believed it could be done in an “environmentally sensitive manner.” His new stance is the exact opposite, that it’s impossible for the process to occur without unacceptable environmental risks.

“I’ve decided that we must take the next step and move from virtually banning fracking to actually banning fracking,” he said. “The choice to me is clear: Either you support a ban on fracking, or you are for fracking.”

He made the announcement alongside state Sen. Bobby Zirkin (D-Baltimore), the lead sponsor of SB 740, which would establish the ban. The House of Delegates passed a ban on the practice by a veto-proof margin two weeks ago.

“Larry Hogan just took a big step for Maryland and the nation in moving us toward” solving global climate change, Mike Tidwell, the executive director of the Chesapeake Climate Action Network, said in a news release.

The controversial process of high-volume fracking has never been used in Maryland, but the state’s two-year moratorium is due to expire in October. Parts of western Maryland sit atop the Marcellus shale, a rock layer several thousand feet below ground laden with natural gas that runs from Ohio to New York. New York and Vermont already prohibit fracking.

larry hogan fracking ban — Geologic Map of Western Maryland | *Maryland Department of Natural Resources; click image for original*

Hogan said his decision was partially based on the state legislature failing to implement rules proposed last year that he said would have been the most stringent in the nation and made it “virtually impossible for anyone to ever engage in fracking in Maryland.” Because the legislature didn’t enact the regulation, Hogan is now supporting a statutory ban.

Prior to Hogan’s announcement, the ban looked unlikely to be approved this session. Legislators feared a veto from Hogan and instead favored extending the moratorium. Sen. Joan Carter Conway (D-Baltimore) had proposed extending the moratorium for two years and requiring each county and Baltimore City to hold referendums next year on whether to ban the practice locally. As the chair of Senate Education, Health and Environmental Affairs Committee, she will decide if the ban bill receives a vote before the moratorium expires.

March 21, 2017

DERs Increasing RTOs’ Data Challenges

By Rich Heidorn Jr.

CARY, N.C. — Stephen Rourke, vice president of system planning at ISO-NE, worries distributed energy resources will force RTOs to change their focus.

“We’re so used to operating at the wholesale level. We dispatched 350 generators for the last 40 years. Now there’s 108,000 solar installations. So we’re kind of getting dragged, whether we like to or not, from a wholesale view of the power system, to a retail view,” he said during the RTO Insider-SAS ISO Summit at SAS headquarters last week.

distributed energy resources (DER) rooftop solar — Stephen Rourke, ISO-NE (left) and Lorenzo Kristov, CAISO | © *RTO Insider*

“What we won’t have [visibility of] is if everybody who has solar panels in their houses puts a 4-kW battery in their garage — and there are hundreds of thousands of those. So that’s going to be a data challenge.

“If you’re 5 MW or greater, you need a [remote terminal unit], you have to have a leased telephone line. Those are thousands of dollars to buy and hundreds of dollars a month to lease the phone line. Your 500-kW solar panel can’t afford to do that, but we have thousands of them. So how do we get the data and how do we process the data? It is … a challenge for us. So we’re going to need help from others certainly with the technology platform.”

‘Layered Control Structure’

Lorenzo Kristov, principal for market and infrastructure policy at CAISO, says it doesn’t have to be the RTO’s headache. He has proposed what he calls a “layered control structure” in which the distribution utilities would aggregate DER data for their RTOs.

“Each tier in this hierarchy only needs to see interchange with the next tier above and below, not the details of what’s going [on] inside because the optimization is happening locally,” he explained. “The ISO then focuses on bulk system integration, while the distribution utility … coordinates the operation of the DERs. The layered control structure reduces complexity, allows scalability and increases resilience and security. And finally the fractal structure mimics nature’s design of complex organisms and ecosystems.”

Kristov urged DER aggregators to bring “use cases” to CAISO to aid it in updating its market rules.

Currently, the ISO uses one of two models for DER: the demand response model and the non-generation resource used for storage. “When you’re charging, you’re using energy at retail; your ability to provide services to the ISO is very limited.

“Several parties have signed up as [DER] aggregators, but they haven’t brought in the resource yet,” he said. “Part of what we’re trying to figure out is what do we need to do to improve those rules. So I would say more active engagement in our stakeholder process [is needed] to bring us specific use cases. How do we want to operate in your markets? What is it we want to do? What are our capabilities? There’s a lot of technical detail that we can’t figure out because it’s the developers who have these things in mind.”

Standards Needed

DER also needs standards, said Ralph Masiello, senior vice president of Quanta Technology. He cited the aftermath of Superstorm Sandy in New Jersey in 2012.

“Too many of those [solar] installations did not disconnect when the distribution circuit went dead and so restoration was held up by the need for utility linemen to come verify that the line was dead before the tree crews could start clearing the debris,” he recounted.

“Normally the utility knows from its SCADA that the line is dead. But if you have just one … PV panel that didn’t de-energize, it’s enough to put high voltage on a downed line and make it dangerous. So there’s kind of a big data opportunity there. The utility needs to know where are those panels and what is their status.”

Solar PV could create a role on distribution systems for synchrophasors that previously have been used mainly in transmission, Masiello said, citing a Department of Energy project testing whether PV panels can be used to develop “synthetic inertia.”

“Can you take a smart inverter on PV — it’s already got communications and … time-synch capability — and build the synchrophasor into that smart inverter? And then you can use it as a key to developing local synthetic inertia from the panels.”

Masiello also said his company is beginning to get requests to do forecasting on the distribution systems.

One need, he said, is identifying distribution lines subject to solar “backfeeding” onto the transmission system, as has become common in Germany and begun happening between 10 a.m. and 2 p.m. in Hawaii.

“In other words, there’s not enough load on a segment of line to be able to absorb all of the solar that’s being generated,”
he explained. Utilities “may have to move some customers from one distribution segment to another.”

March 21, 2017

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:25)

Members will be asked to endorse the following proposed manual changes:

A. Manual 13: Emergency Operations. Revisions developed in response to new NERC standards.

B. Manual 37: Reliability Coordination. Revisions developed in response to new NERC standards.

C. Manual 1: Control Center and Data Exchange Requirements. Revisions developed in response to new NERC standards.

3. FERC Order 825 – Shortage Pricing (9:25-9:45)

Members will be asked to endorse the proposed shortage pricing and operating reserve demand curve solution and associated manual revisions. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)

4. Draft Pseudo-Tie Agreements (9:45-10:05)

Members will be asked to endorse a pro forma pseudo-tie agreement and a reimbursement agreement for pseudo-ties into PJM, along with related Tariff and Operating Agreement revisions. (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.)

5. Cost Development Manual Revisions (10:05-10:35)

Members will be asked to endorse revisions to Manual 15 and the Operating Agreement regarding hourly offers and fuel-cost policies. (See PJM Fuel-Cost Policy Changes to Take Effect in May.)

6. Opportunity Cost Calculation (10:35-10:50)

Members will be asked to endorse a proposed problem statement and issue charge by Bob O’Connell of Panda Power Funds regarding calculation of opportunity costs for units with less than three years of historical LMPs. The initiative would evaluate whether the opportunity cost calculator included in PJM’s Markets Gateway produces the same results as that used by the Independent Market Monitor, Monitoring Analytics. It also would consider updating the calculators to reflect the nonperformance penalties under Capacity Performance. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)

7. Modeling Generation Senior Task Force (MGSTF) (10:50-11:00)

Members will be asked to endorse a draft charter for the MGSTF, an outgrowth of the Combined Cycle Owners User Group, which concluded that a more detailed generator model for combined cycle units might also be applicable to other steam units. The task force will consider expanding the model used by PJM to improve the ability to represent components of all generation types.

8. Incremental Auction Senior Task Force (IASTF) (11:00-11:10)

Members will be asked to endorse a draft charter for the IASTF, which will consider changes to the Incremental Auction process and structure, excess capacity sales, and PJM participation in the auctions.

9. Replacement Capacity (11:10-11:40)

Members will be asked to endorse a revised version of a previously rejected problem statement and issue charge regarding procurement of replacement capacity in Reliability Pricing Model Incremental Auctions. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)

Members Committee

There are no items up for endorsement.

— Rory D. Sweeney

March 21, 2017

Ott Seeks ‘Resilience’; Clark Handicaps ZECs

By Rich Heidorn Jr.

CARY, N.C. — PJM CEO Andy Ott said last week the RTO will look for ways to incorporate “resilience” in its markets and system operations, providing hints at a white paper it will release later this month on the issue.

coalition for clean coal electricity andy ott tony clark — Clark | © *RTO Insider*

Speaking at the RTO Insider/SAS ISO Summit last week, Ott said the initiative was sparked by fuel security concerns — the risks of sabotage or cyberattacks on grid assets or gas pipelines — and a desire to recognize the reliability value of baseload nuclear and coal plants struggling to compete in the PJM market. Later in the panel discussion, former FERC Commissioner Tony Clark — participating via phone after snow canceled his flight from D.C. — forecast how the commission and the courts may rule on zero-emission credits that provide additional revenues to nuclear plants.

Ott said one possible shift in PJM would be changing contingency plans from replacing the largest single generator to ones that consider the loss of a gas pipeline supplying multiple generators.

“All the generation connected in a certain section of that pipeline could go off very quickly if it loses pressure because of an explosion or some event. Maybe we should be operating to the loss of that and look at that operational risk inside the market and price that in so the units that didn’t have that kind of fuel security risk would be worth more money,” Ott said. “That would help, of course, the resources that are less dependent on just-in-time fuel” such as nuclear and coal. Ott also said PJM will seek to become more “dynamic” in its management of operations.

Concern over Pipelines, Transmission Corridor

“One obvious [example] is to look at the way we deploy synchronized reserves or operating reserves and expand the contingency set that you’re looking at to include pipeline contingencies. … Or if you have a transmission corridor that you’re very worried about — potentially include that as part of your constraint set. So when you’re dispatching generation or deploying demand response, you’re essentially recognizing that double contingency or triple contingency as part of operations in certain circumstances. Not 8,760 hours [per year] but when you think that vulnerability exists, you can price it in.”

It also could mean system restoration plans becoming less dependent on individual transmission lines or fuel sources, Ott said.

Ott did not offer details on how fuel security would be priced into the markets. The RTO has already taken steps to address reliability concerns with its Capacity Performance rules, which increased penalties for nonperformance and rewards for overproduction during emergencies.

Coal Group Petitions PJM, MISO

On Friday, meanwhile, the American Coalition for Clean Coal Electricity (ACCCE) sent Ott a letter calling on PJM to take steps to prevent further retirements of coal-fired generation and “take into account the likelihood of changes to federal environmental policies.”

“We are confident the new administration will withdraw or rewrite environmental regulations that are causing, or could cause, more coal retirements,” ACCCE CEO Paul Bailey wrote. “These rules include the Clean Power Plan, Coal Combustion Residuals, Effluent Limitations Guidelines, Cross State Air Pollution Rule and Regional Haze.”

Bailey said the Capacity Performance rules were helpful but insufficient. “We do not think these changes go far enough in recognizing the advantages of baseload coal-fired generation. In particular, the changes have not led to higher capacity prices that are necessary to keep coal plants from prematurely retiring,” he wrote.

ACCCE says 121 coal-fired generators totaling 20.1 GW have retired in PJM, most because of environmental regulations, and another 28 plants (8.9 GW) have announced plans to shut down.

The group also sent a letter to MISO CEO John Bear asking the RTO to change rules “to ensure the reliability attributes of coal-fired generation … are properly valued.” MISO has lost 103 coal-fired generators (8 GW), with another 45 retirements (10.5 GW) pending.

Former Commissioner: FERC May Reject ZECs

Former Commissioner Clark, now a senior adviser at Wilkinson Barker Knauer, said zero-emission credits approved for nuclear plants in New York and Illinois — and under consideration in Connecticut and other states — may be rejected by FERC or the courts because of their impact on wholesale market prices. (See related story, Connecticut Moves Closer to Equating Nuclear with Renewables.)

Clark called ZECs the third iteration of states’ efforts to build or preserve generation within their borders. Last April, the Supreme Court rejected Maryland’s contract-for-differences with the developer of a combined cycle unit, saying that by tying the contract to PJM capacity prices, the state had violated federal jurisdiction.

In May, American Electric Power and FirstEnergy withdrew power purchase agreements that Ohio regulators had approved with their unregulated generation after FERC indicated it would review the deals for violations of affiliate abuse rules. “The merchant generators basically did a very surgical strike in [their] filing at FERC” in requesting the affiliate review, Clark said.

With ZECs, “the states … have really gotten craftier about how they can [preserve at-risk generators],” said Clark, noting that they were designed to be similar to state renewable energy credits (RECs).

“Merchant generators have … said these RECs are an out-of-market subsidy [that] distort prices. And the commission has said, ‘OK, theoretically we understand what you’re saying.’ But there wasn’t enough provable harm for the commission to really do anything about it,” Clark said. The RECs “were either conceptual at the time of the challenge … or it was a small enough part of the market … that it didn’t seem like it was a big enough issue that the commission could act on. So effectively the commission could punt on that issue.

“Now if you’re talking about certain regions of the country where nuclear units are 20%, 30% of the market, or if you’re talking about other out-of-market interventions like in the Northeast — you’ve heard about long-term power contracts … with Canadian hydro — that might be 30% of the state’s energy needs.

“Well that does have a very material impact on the market themselves, so that will be a challenge for the commission to see if this is a zero-sum game, or the commission will have to declare in some ways these things federally jurisdictional and carve the states out. Or is there a way to thread the needle? That’s what each of the ISOs that’s dealing with this is doing.

“Here’s where it will get to be very tricky for the commission,” Clark concluded. “I’m not sure exactly how it will end up dealing with it.”

March 21, 2017

IRC: Renewables’ Future Depends on Grid’s Ability to ‘Accommodate’

By Tom Kleckner

North America’s independent grid operators released a report Thursday that concludes the “ongoing effectiveness” of renewable technologies will depend directly upon the electric system’s ability to “accommodate them.”

The ISO/RTO Council (IRC)’s report, “Emerging Technologies: How ISOs and RTOs can create a more nimble, robust bulk electricity system,” concludes the future of the North American power grid depends on effectively adding renewables, the accuracy and availability of data from behind-the-meter resources and coordinating these distributed energy resources at the grid-operator level to preserve reliability.

The report captures the results of a study conducted by the IRC’s Emerging Technologies Task Force (ETTF), which was formed in 2015 to review the deployment of new technologies and identify where that deployment intersects with operational and policy considerations.

IRC renewables nick brown — “Technology precedes policy,” says SPP CEO Nick Brown, chair of the ISO/RTO Council. | © *RTO Insider*

The report notes more than 80% of North America’s wind and solar capacity lies in regions served by IRC members. These technologies face a serious challenge, the report said — the electric system itself.

SPP CEO Nick Brown, the IRC’s current chair, noted grid operators from different geographic regions “overlap … in their thinking” of the role emerging technologies will play.

Technology Precedes Policy

“Here’s the challenge: Technology always precedes policy,” Brown said during a panel discussion last week at the RTO Insider/SAS ISO Summit. “And as technology presents things, then we have to understand how to manage them [through] appropriate policies.”

The IRC is an affiliation of nine nonprofit grid operators that serve two-thirds of electricity consumers in the U.S. and more than half in Canada.

“Any time the IRC speaks with strong consensus on a matter like it has done here, I hope our industry takes notice,” Brown said in a news release.

“Each of the IRC member organizations is unique,” said ETTF Chair Edward Arlitt, of Ontario’s Independent Electricity System Operator. “One ISO or RTO may have greater solar capacity in their region, another may be farther along in their handling of DERs, and all of us have regulatory and operational constraints unique to the provinces, states and regions in which we serve.”

The task force used a straw poll to determine that handling emerging technologies was the highest-ranked priority among IRC members.

‘Imperatives’

The task force’s research produced what it called imperatives necessary to ensure the grid’s continued reliability and efficiency as the penetration of emerging technologies increases:

Manage the variability of supply and increasing levels of renewable integration enabled by emerging technologies. Is there enough “cohesive innovation” happening to integrate renewable generation, grid-scale energy storage and microgrids’ disparate components into the Bulk Electric System?

The IRC said while it is agnostic to specific technologies that may facilitate renewable integration, it supports policies that “accommodate emerging renewable integration technologies” and pursuing “continentwide consensus” on how much integration will be achieved through regional or interregional trade.

IRC renewables ceo nick brown — Computer-modeled load profiles for CAISO under various future scenarios of 20%-50% PV penetration.

The report recommends avoiding committing too early to specific technologies and calls for a “suitable policy environment” to ensure new technologies and approaches continue to be developed, tested and applied to renewable integration.

Address the IRC members’ lack of consistent, reliable, DER-related data as the grid becomes more distributed and less predictable.

The report says the lack of consistent and reliable data — such as between SCADA systems and new phasor measurement units (PMU) — should not constrain “situational-awareness arrangements” across transmission/distribution connections. It also says RTOs should have access to basic, static DER data series in their service territories. The task force said location, size and technological capabilities are examples of data needed to manage an increasingly distributed system.

The task force recommended developing an operations data framework flexible enough to handle local differences in DER penetrations.

Noting FERC’s November 2016 Notice of Proposed Rulemaking, which would require wholesale markets to accommodate energy storage and DER, the IRC suggests a formalized framework to help RTOs “harness the capabilities and manage the risks” of intermittent DER growth. (See FERC Rule Would Boost Energy Storage, DER.)

The task force recommends jurisdictions with distribution system operators (DSO) conform to standards that allow safe interaction between DSOs, non-utility entities and the Bulk Electric System. It said it supports policies that ensure if distribution-level variability poses risk to system reliability, RTOs have “appropriate authority” over DERs or mitigate their impact on the grid.