Page 1545 – RTO Insider

March 24, 2017

EE, Renewables Flattening ISO-NE Demand for Next Decade

By Michael Kuser

WESTBOROUGH, Mass. — Energy efficiency, lower economic growth and burgeoning home solar installations will reduce ISO-NE’s net load through at least 2026, Manager of Load Forecasting Jon Black said Wednesday.

While the region’s gross annual load is expected to rise by 8.5% to 152,593 GWh by 2026, load net of behind-the-meter solar and passive demand resources will drop 5.2% to 120,181 GWh. “There were no methodology changes in the [gross load] forecast since last year,” Black told the Planning Advisory Committee on March 22. “It’s just refreshes of the data.”

ISO-NE Renewables passive demand resources — | *ISO-NE*

The region’s weather-normalized net electric consumption declined 1.5% in 2016 versus 2015, according to the RTO’s draft 2017 Capacity, Energy, Loads and Transmission energy and summer peak forecast. The completed forecast will be published by May 1.

Compared to last year’s forecast, the new report projects the 2025 annual energy demand will be 3.9% lower. The summer 50/50 forecast is approximately 3% lower, while the 90/10 forecast is 2.7% lower.

Reasons for the drop include a 15% increase over last year’s forecast in projected behind-the-meter solar for 2025 and an 11% increase in projected energy efficiency, the latter due to a revised production cost escalation methodology.

The grid operator projects approximately 2,444 MW of PV development over the coming decade, for a total of 4,362 MW in 2026.

Black said that they are now getting more granular data on load reduction because of PV after increasing the number of installations monitored from 1,200 to 9,000. The RTO counts distributed solar — those less than 5 MW — as reducing net load.

Passive demand resources climbed 11% last year to 14,380 GWh. Passive demand resources include the use of energy-efficient appliances and lighting, “smart” cooling and heating technologies that cycle air conditioners on and off, and measures to shift electricity use to off-peak hours.

Paul Peterson of Synapse Energy Economics asked RTO officials about the projected annual increases in PV resources. The report shows a 445-MW increase in 2017 PV versus 2016, a 23% jump.

“The PV is going to eat up large number of megawatt-hours. That will affect generation developers. If the pie continues to shrink, it becomes very difficult for generators to earn the same amount of revenue from energy sales,” Peterson said. “Generators need to know if solar will be five, six or eight thousand megawatts in 2026. Will the trend accelerate?”

“There’s a lot of uncertainty over that, around when this stuff becomes economic,” responded Black. “A lot depends on rate structuring. We’re waiting for clearer signals.”

ISO-NE officials told Vermont legislators in January that the capacity market “will be an important revenue-balancing mechanism to ensure resource adequacy as renewable resources drive down revenues in the energy market.”

Black said expectations of lower economic growth were based on a Moody’s Investor Service’s forecast that predicts New England’s share of the U.S. gross domestic product declining from more than 5.7% in 2000 to just more than 5% by 2026.

March 24, 2017

CAISO Sees Ups and Downs in Q4 Real-time Prices

By Robert Mullin

CAISO’s real-time market experienced an uptick in volatility during the fourth quarter of 2016, as five-minute prices at times spiked to well above day-ahead and 15-minute levels on unexpected variability in output from solar resources.

On the flip side: Solar generation increasingly sent mid-day prices into negative territory during the quarter, a trend that the ISO’s internal Market Monitor says is continuing into this year.

CAISO day-ahead market negative prices — CAISO’s Q4 negative prices occurred most frequently during mid-day, the period of highest solar output. | *CAISO*

“November did see a fairly high frequency of prices above the $250 level in the five-minute market,” Gabe Murtaugh, a senior analyst with the ISO’s Department of Market Monitoring, said during a March 22 call to discuss his group’s quarterly market issues report. “You’d have to go back to the beginning of 2015 to see this frequency.”

In November, real-time prices surged to $250 or higher during nearly 1.5% of intervals, compared with fewer than 0.4% of intervals during the same period in 2015. Prices hit $750 or more during 0.6% of intervals, up from 0.3% a year earlier.

Murtaugh attributed the prices spikes to more cloud cover than was forecast by CAISO, translating into lower solar output than was accounted for in the day-ahead market during specific intervals. The ISO was forced to move up the bid stack to secure higher-priced resources in real-time to cover the shortfall — especially during the afternoon ramp as solar resources began to reduce output.

“This outcome resulted in part from a combination of solar deviations and tight supply conditions during intervals when system ramping needs were greatest,” the department said in its report.

Contributing to the price discrepancies between the five- and 15-minute markets were differences in the solar forecasting methodologies used for each, an issue the ISO addressed through changes to its forecasting software in December.

Still, instances of high prices during the fourth quarter were “fairly irregular,” according to Murtaugh. More frequent were intervals of negative prices, the Monitor noted.

The department observed negative prices during 4.7% of intervals during the five-minute market and 1.8% of those in the 15-minute market. By comparison, during the same period a year earlier, negative prices occurred in 2% and 1% of five- and 15-minute market intervals, respectively.

The last quarter of 2016 also saw five-minute prices go negative nearly 20% of the time during the 10 a.m. interval — the beginning of the mid-day period most subject to solar-drive price dips.

Nearly all of the negative prices were the result of the ISO’s market mechanisms — and not the result of out-of-market operations to curtail output.

“These are conditions where an economic downward dispatch is issued to a unit with a negative marginal cost, so negative marginal cost units are setting the marginal price in the system,” Murtaugh said. “This is a solution that is arrived at from the market optimization and it’s similar to any other solution that we would see in the market during other times of the day when marginal costs are set at a marginal level.”

The Monitor’s data showed that most of the negative prices held to a range between $0 and -$50/MWh.

Carrie Bentley of Resero Consulting wondered where most of the negative prices clustered — closer to $0 or $50?

“Off the cuff, it tends to be more clustered between the $0 and $25 range,” Murtaugh responded. “That typically tends to be the amount of tax incentives that are given out on a per-megawatt-hour basis to solar facilities and wind facilities — and those tend to be the ones we see setting the price more frequently.”

Murtaugh also offered call listeners a “teaser” regarding the first quarter: “For the data that we’ve already looked at in 2017, the [negative price] numbers are fairly high for the first quarter as well.”

Wei Zhou, a senior project manager with Southern California Edison, probed Monitor staff about an observed increase in negative prices in the ISO’s day-ahead market this year.

“What’s the expectation for the frequency of negative pricing in the day-ahead market?” Zhou asked.

Keith Collins, CAISO manager of monitoring and reporting, called the development an “improvement” that would allow the ISO to better align resource commitments in the day-ahead market with actual conditions in real-time, decreasing the potential for oversupply.

“So shifting [negative prices] to the day-ahead is not necessarily in and of itself a bad thing, but it’s not a trend that was observed prior to the last few weeks,” Collins said, adding that it was a topic that could be covered in a future Market Performance Planning Forum.

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

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.