With Solar Eclipse Looming, CAISO Weighs its Options

By Robert Mullin

For nearly three hours this summer, a solar eclipse will blackout much of California’s growing volume of solar generating resources, forcing the state’s grid operator to cover the shortfall with a bevy of resources equipped to quickly react to dispatch instructions.

CAISO is already well into developing its response to the Aug. 21 event.

On that date, the California sun will be reach its dimmest point at 10:22 a.m., the eclipse’s moment of maximum “obscuration.” By that time, CAISO’s “net load” — the portion of electricity demand not served by renewable resources — will have surged to about 6,000 MW more than what it would normally be on a sunny summer day.

The primary reason: The temporary loss of 5,600 MW of energy from grid-connected solar that would typically be generating at that time under full-sun conditions.

An accompanying drop-off in output from behind-the-meter solar will add to the impact, bumping up net load by about 8%.

Solar declines are forecast to be uneven throughout the state, with obscuration rates ranging from 76% in the northern San Joaquin Valley to 58% near the border with Mexico.

caiso solar eclipse — The eclipse will have its greatest impact on solar generation in Northern California, where “obscuration” rates will be above 75%. | *CAISO*

“We’re going to start losing solar during the morning ramp,” Amber Motley, CAISO manager of short-term forecasting, said during a May 1 meeting of CAISO’s Board of Governors, where she described the ISO’s ongoing preparations. (See CAISO Planners Looking Ahead to Summer 2017 Solar Eclipse.)

Motley called the timing of the eclipse “a little bit of a blessing” compared with the situation faced by European system operators in 2015, when a similar event there coincided with the sharper evening ramp.

Still, the ISO expects to lose about 70 MW of solar output per minute from the start of this summer’s eclipse to its fullest point, accelerating the morning ramp to two to three times its normal rate.

Mark Rothleder, CAISO vice president for market quality and renewable integration, pointed to another notable detail: Aug. 21 falls on a Monday.

“It’s not unusual on a Monday during summer, especially if you have several hot days leading up to that Monday, that you could have a high load and potentially a peak condition for the year,” Rothleder said.

But Motley counted other blessings, including the fact that populous areas of California are subject to “marine layers” — low-altitude cloud cover — during August mornings.

And then there’s heavy snowpack that is feeding the state’s hydroelectric system to the point of oversupply this spring. (See Spring Oversupply Lifts CAISO Curtailments.)

“We know we have a lot of hydropower this year. It’s a blessing,” Motley said, referring to the ramping capability of those resources. “That’s something we expect will still be available in August.”

To help manage the ramp, CAISO will increase its coordination with hydroelectric producers to ensure that they’re prepared to bid into the wholesale market that day. The ISO also plans to increase regulation reserves by about one-third — 350 to 400 MW, a number that staff will revisit after performing market simulations. Those simulations will also provide insight into whether the ISO needs to make any adjustments to how its flexible ramp product performs during the eclipse period.

CAISO will also “coordinate very heavily” with natural gas suppliers to ensure that gas-fired generators procure an adequate supply of fuel.

Another potential option: the manual curtailment of renewables ahead of the eclipse.

“I think that the market simulation will really show us how the market can handle this particular set of movements throughout the day, but [curtailment] was something that was utilized in Europe,” Motley said.

With solar output expected to increase at a rate of 90 MW/minute coming out the eclipse, the ISO is considering placing a constraint on that upward ramp, which will necessitate a corresponding downward ramp for dispatchable resources.

“That 90-MW return is quite steep,” Motely said.

The ISO will depend on the Western Energy Imbalance Market (EIM) for additional measures. With other EIM areas experiencing the eclipse at different times, the market’s software “will be able to optimize EIM transfer capability and use that as a feature as we go through the eclipse,” Motley said.

Grid-connected solar output will decline by 866 MW in other EIM balancing areas during the eclipse. Nearly all the reductions will be concentrated in Arizona and Nevada.

CAISO staff plan to present stakeholders with their preparations for the eclipse during a Market Performance and Planning Forum on July 18 — about one month before the event.

“We look forward to being informed about this,” said ISO board member Angelina Galiteva. “This is interesting — and it’s going to be a test case for what’s to come in the future on a much more regular basis.”

May 3, 2017

FERC Greenlights MISO Cost Allocation for SPP Settlement

FERC has approved MISO’s uncontested settlement for allocating costs among its members for the use of SPP’s grid.

The settlement covers the costs for transmission flows between MISO Midwest and MISO South in excess of 1,000 MW. It is based on an agreement the RTOs struck in early 2016.

The May 2 letter order accepts MISO’s proposal to allocate costs using a declining percentage through a load ratio calculation and an increasing amount through a flow-based benefits methodology (ER14-1736). (See “Cost Allocation Set in MISO-SPP Settlement,” MISO Market Subcommittee Briefs.) The allocation will be used from Feb. 1, 2016, to Jan. 31, 2021:

Feb. 1, 2016 to Jan. 31, 2017: 45% load-based / 55% flow-based;
Feb. 1, 2017 to Jan. 31, 2018: 40% load-based / 60% flow-based;
Feb. 1, 2018 to Jan. 31, 2019: 27.5% load-based / 72.5% flow-based;
Feb. 1, 2019 to Jan. 31, 2020: 17.5% load-based / 82.5% flow-based; and
Feb. 1, 2020 to Jan. 31, 2021: 10% load-based / 90% flow-based.

While waiting on the order, MISO collected payments to SPP using a market ratio share method, and that status quo will stay in place for the funds collected from Jan. 29, 2014, to Jan. 31, 2016. MISO pays SPP $1.3 million per month, subject to true-up. Staff say MISO will begin resettling amounts collected after Jan. 31, 2016, once the allocation method was approved.

MISO filed the settlement package on Aug. 31, and a FERC administrative law judge certified it in October.

— Amanda Durish Cook

May 3, 2017

PJM Stakeholders Offer Different Takes on Markets’ Viability

By Rory D. Sweeney

WASHINGTON — If anyone thought FERC dragging state and RTO stakeholders here for a technical conference might jolt everyone on the PJM playground into playing nice with each other, Robert Erwin of the Maryland Public Service Commission quickly disabused the standing-room-only crowd of that notion.

“Maryland does not consider the PJM markets as the sole definer of resource adequacy and reliability. … We’re not relying solely on Dr. Bowring and President Ott,” he said, referring to Joe Bowring, PJM’s Independent Market Monitor, and PJM CEO Andy Ott. “If the lights really do go out, Maryland ratepayers are not going to storm [PJM’s offices in] Valley Forge with pitchforks and torches. They’re going to come to the Maryland commission, and they’re going to say, ‘How did you let that happen?’ And when we talk to that reporter from The Baltimore Sun, we don’t want to be a position saying, ‘Well, Dr. Bowring and President Ott told us it was all going to be fine.’”

Erwin suggested that the RTO might need to rethink its premise of being cost-based and resource-neutral. His perspective was contrasted by other state regulators on the panel, who offered a gradient of opinions on PJM’s adequacy. Richard Mroz, the president of New Jersey’s Board of Public Utilities, said state regulators need help keeping up with industry oversight, while Andrew Place, the vice chairman of Pennsylvania’s Public Utility Commission, said he is “fuel-agnostic” and cautioned against increasing complexity and decreasing transparency and cost efficiency in the market.

PJM ott bowring capacity market — Sheahan | © *RTO Insider*

Brien Sheahan, chairman of the Illinois Commerce Commission, defended the state’s controversial decision in December to legislate zero-emission credits that ostensibly created subsidies for two Exelon-owned nuclear plants. While the RTO plays “an important role,” and will continue to, he said “markets … exist to serve state purposes.” States that have “legitimate environmental concerns” have the legal authority to require RTOs to “reflect those priorities,” he said.

Place called for a different approach. “I would much rather see an integrated carbon price that’s fuel-agnostic, and I don’t think it will cause reliability issues,” he said.

Mroz reiterated his pride, as he often does, with New Jersey’s generator diversity — the Garden State powers itself mostly with nuclear, gas, coal, solar and wind — but expressed a common concern about fuel security.

“What if there is impingement of resources?” he asked, noting that the removal of integrated resource plans has reduced states’ ability to address such concerns.

The Subsidy Heard Round the World

The second PJM panel in the May 1 conference was made up of Bowring, Ott and representatives from generators, utilities, state consumer advocates and special-interest groups. (See also Power Markets at Risk from State Actions, Speakers Tell FERC.) Their comments often circled back to the ZECs approved in Illinois and the impacts they have on the market.

“The new war on coal is subsidies,” Dynegy CEO Robert Flexon said. “Coal cannot compete with nuclear subsidies.”

Jennifer Chen of the Natural Resources Defense Council said fossil fuels also receive subsidies. “Subsidies are everywhere, and they’re hidden,” she said.

Bailey (left) and Chen | © *RTO Insider*

Bowring said that only some nuclear and coal units in PJM are unable to run economically and reiterated Place’s endorsement of in-market pricing signals over state actions that bypass the market. “Clearly a market-based price on carbon is better than a subsidy,” he said.

Ott asked for FERC’s help in fixing a “fundamental inconsistency” in PJM’s energy market that creates negative prices by valuing some environmental externalities and not others. “We try to move 400 or 500 MW of wind, and we’ve got to send negative prices for a substantial number of hours,” he said. “It’s unsustainable and devalues assets that are inflexible and can’t move.”

However, Mike Cocco of Old Dominion Electric Cooperative saw “cheap gas” and high-efficiency gas-fired units as the main drivers of market stress rather than subsidies.

The Future of RPM

Poulos (left) and Sundararajan | © *RTO Insider*

Throughout the day, acting FERC Chair Cheryl LaFleur and Commissioner Colette Honorable pressed speakers to explain what they thought needed to be done.

Asked about the future of PJM’s capacity market, Erwin was frank in his advice. “We would not encourage either you or PJM to continue to tweak the [Reliability Pricing Model] or the [minimum offer price rule]. … Every single year, there have been proposals for changing RPM. We don’t think that continuing to tweak that model is going to be very constructive.

“Do you really want to get rid of all of the nukes because they’re uneconomic? Is that really a good idea?” he asked.

“I’m saying no,” Honorable responded.

“I’m saying no too,” he said, adding that he is skeptical of letting all non-intermittent resources transition to gas.

“The markets don’t value the externalities that the state values, particularly the environmental attributes, but also other valuable attributes of baseload nuclear,” Sheahan said. “This was an urgent conversation three years ago. This is a crisis today.”

Place preferred consistency. “I’m torn. I’d probably come down that I’d rather see tweaking of capacity markets than starting fresh, though it comes with a lot of baggage,” he said.

He said the energy market, which dispatches generation in real time, is better for addressing issues such as the uneconomic nature of nuclear plants rather than trying to manipulate the capacity market to address it.

Collaborate, Don’t Litigate

One thing seemingly every speaker agreed on was that — having been frustrated with the courts’ narrow rulings on state-federal jurisdictional issues — collaboration to resolve the issues at the RTO would be more productive than litigating them. (See Court’s Reticence Frustrates Energy Bar.) The commissioners agreed. “I appreciate the fact that you’ve thought about … how we can do so in a way that allows us all to keep our eyes on the prize and [reduce] additional years of waiting around for a solution,” Honorable said.

Can a market with 13 states and D.C. find agreement?

“I do think that we can value these other attributes,” Mroz said. “The question is whether we all agree about what those valuations are, or what the attributes are.”

Plenty to Go Around

Honorable said the commission took away from the conference that it needs to become more active in coordinating the discussion, such as ordering a deadline for the RTO to determine what externalities it needs to address and how to incorporate them. She asked what the commission can do to further assist the process.

“We need to somehow discipline the output of generation in order to keep the supply/demand balance,” Ott said. “The resources that are needed to serve load should participate in setting price. It’s as simple as that.”

Chen said part of the problem is an overabundance of gas-fired units able to drastically lower auction clearing prices because of cheap fuel.

Bowring challenged that argument, saying the additional supply allows for lower prices and energy benefits. His protest drew a laugh from the crowd and prompted Ott to exclaim, “It’s a bargain!”

Erwin noted that PJM has a 22% reserve margin — well above its 15% requirement — “that potentially isn’t used at all.”

“Maryland does not see an adequacy problem in PJM,” Erwin said, asking FERC to consider consumers who pay the bills. “There’s only one source of revenue for all of this, and that’s your neighbors and my neighbors.”

[Editor’s Note: RTO Insider will have additional coverage of the technical conference in the May 9 newsletter.]

FERC’s agenda said the technical conference “may address matters at issue” in the following pending dockets:

EL16-49 (See FERC Rescinds AEP, FirstEnergy Affiliate-Sales Waivers.)
ER15-623, EL15-29-006, and EL15-41-002 PJM Capacity Performance plan (See Clean Energy Advocates Appeal FERC’s Capacity Performance Rulings.)
ER14-1461, EL14-48, ER17-367 (See PJM Monitor Asks FERC to Act on ‘Paper Capacity’.)

May 2, 2017

Power Markets at Risk from State Actions, Speakers Tell FERC

By Rich Heidorn Jr. and Michael Kuser

WASHINGTON — RTO capacity markets are in serious danger from state renewable procurements and subsidies for nuclear plants, speakers told FERC on Monday.

FERC RTO Capacity Markets — Bentz | © *RTO Insider*

Jeffrey W. Bentz, director of analysis for the New England States Committee on Electricity, said failing to coordinate ISO-NE’s capacity market with state renewable procurements will lead to oversupply and excessive costs to ratepayers in the region.

“Maybe that’s not in the next three to five years,” he said on the first day of a two-day technical conference on the impact of state electricity policies on ISO-NE, NYISO and PJM. “But down the road, clearly we can see that train wreck coming and it would probably be the end of the markets as we know them today.”

New Hampshire Public Utilities Commissioner Robert R. Scott also had a warning: “It is not possible to fully preserve the benefits of competition … with a market design that seeks to replace low-cost resources with resources that cost more,” he said in his written testimony.

FERC scheduled the conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).

The conferees discussed the grid operators’ efforts to address state-market conflicts, including white papers by PJM, and the New England Power Pool’s Integrating Markets and Public Policy (IMAPP). The conference also came as FERC has pending before it challenges to zero-emission credits for nuclear generators in New York and Illinois.

FERC staff indicated the high stakes posed by increasing tensions between state policies and RTO/ISO resource adequacy efforts, asking witnesses to consider whether there will be “a diminished role for the RTO/ISO.”

Taking Matters into Their Own Hands

During the hearing, some state officials said they had taken power procurement into their own hands because the capacity markets haven’t delivered the types of resources they desire.

Among the problems: the lack of a price on carbon emissions and no recognition of the value of fuel diversity.

“The market was only delivering one product: natural gas [generation],” said Robert Klee, the commissioner of the Connecticut Department of Energy and Environmental Protection, who said the dependence on gas caused reliability concerns during the winter peaks, when generators must compete for fuel with heating customers. “We’ve been pretty lucky to have mild winters the last few years. We don’t want to go back to the polar vortex.”

Klee said difficulties getting additional gas pipelines to supply the region’s generators had heightened state officials’ concerns.

Still, he suggested state procurements likely won’t provide all of the new power supplies needed for New England states planning to electrify transportation and building heating. “That’s a lot of growth,” he said.

Angela M. O’Connor, chair of the Massachusetts Department of Public Utilities, said the markets “have provided tremendous benefits” and that the capacity market has produced new generation to maintain reliability.

“But we are at a crossroads, and what the legislature requires us to do, we have to do,” she said, referring to mandates to reduce greenhouse gas emissions by 80% below 1990 levels by 2050, and procure hydropower and offshore wind.

“The wholesale markets [are] … not going to get us our large-scale hydro or the offshore wind — or, frankly, gas pipelines.”

Susanne DesRoches, deputy director of infrastructure policy for New York City, agreed. “We support the wholesale markets, but we see that innovation is needed,” she said.

Scott Weiner, deputy for markets and innovation at the New York State Department of Public Service, said the state is at an “inflection point.”

“Is there a role for the markets? Absolutely. Is it going to change? Probably. … The energy markets will always be there. The capacity market may not be.”

Seth Kaplan, senior manager of regional government affairs for EDP Renewables, said the markets were constructed with gas turbines in mind at a time when renewables had little market share. Given the changes since then, he said, “it’s not surprising that a square peg doesn’t fit into a round hole.”

Grid Operators Respond

Matt White, chief economist for ISO-NE, insisted the RTO had no intention of relinquishing its role as the guarantor of resource adequacy standards.

“We believe that resource adequacy requires a single point of responsibility and accountability. ISO-NE currently bears this responsibility. Another option is for the states to take on this role through local utilities; to date, however, the New England states have not expressed interest in assuming this role,” the RTO said in its written testimony.

NYISO CEO Brad Jones said that while the ISO supports New York’s ZECs, the program needs to be incorporated into the market. He said it could take three years to work out a solution.

Generators’ Concerns

That was too long for witnesses representing independent power producers.

“The challenge before the commission, the states and all other stakeholders is no less than the question of whether the power industry will continue to use competitive markets as the basis for investment decision-making,” Peter Fuller, vice president of market and regulatory affairs for NRG Energy, said in his written testimony.

In his response to questions, Fuller was a bit more optimistic: “We believe the markets can be adapted to give the states what they need … and figure out a way for those resources to have their role in the markets while not undermining the markets for those of us who have invested strictly on the basis of market revenues.

“I don’t think we’re are the tipping point yet,” Fuller said. “But if we don’t move fairly quickly [to] … ensure that markets can actually support the … renewable-based future … then we could very well tip over.”

John Reese, senior vice president of Eastern Generation, said the issue is particularly acute in NYISO, which has a one-year forward capacity auction, unlike the three-year auctions in PJM and ISO-NE. Eastern Generation operates almost 5,000 MW of generation in NYISO and PJM, including 18% of New York City’s capacity.

“I can’t wait for seven years or eight years for this to work out,” he said. “Regardless of which model we end up with, we need to be sending investment signals now!”

Déjà vu

John Shelk, CEO of the Electric Power Supply Association, lamented that policymakers had not accomplished more since FERC’s September 2013 technical conference on the Eastern capacity markets. (See Capacity Market Attracts Praise, Criticism at FERC.)

“The one area of agreement is exactly the place that we’re headed to that everyone said four years ago, ‘Don’t go there,’ which was tranches: ‘Let’s pick X amount of nuclear, X amount of coal, X amount of gas.’ Now it’s worse. Now we’re not just picking fuels, we’re picking specific [generating] units that otherwise would have exited.

“This may have started in New York last year … but in short order it was adopted in my home state of Illinois and as everybody knows, it’s now being actively considered in Ohio, Pennsylvania and New Jersey and Connecticut. So this isn’t just a threat to the market in New York.” (See related story, PJM Stakeholders Offer Vastly Different Takes on Markets’ Viability.)

Without changes, Shelk said, his members may have to seek state approval of “flexible energy credits” to support generators that provide the ramping needed to support variable resources.

New York regulator Weiner also called for urgency. “We’ll be having this same discussion two years from now unless there’s a recognition that things have changed,” he said.

LaFleur: FERC Will Act

In opening remarks Monday, acting FERC Chair Cheryl LaFleur acknowledged, “I’m very well aware that the wholesale markets … only can exist and continue through the buy-in of the states.

“I have said very many times there are three ways this could go: a designed market solution, a litigated outcome or a planned change in the regulatory construct of how we handle resource adequacy. The fourth outcome — an unplanned change in the regulatory construct, or unplanned and piecemeal regulation — is one that I think we should avoid because I think it would be a bad outcome for customers and market participants.

“Once we restore our quorum, this commission will almost certainly have to decide litigated complaints that are already pending before us, even as regions may be working on market solutions to file with us,” she continued. “While we can’t decide anything immediately because we lack a quorum, we must shape options and recommendations for a FERC 2.0 based on the record we develop today and tomorrow.”

[Editor’s Note: RTO Insider will have full coverage of the technical conference later this week and in the May 9 newsletter.]

May 2, 2017

FirstEnergy Hopeful on State, Federal Support

By Jason Fordney

FirstEnergy is encouraged by possible new state and federal support for nuclear and coal-fired plants, but the company said it has not changed its plan to divest its merchant generation and become a fully regulated company by the middle of next year.

“There is absolutely no change in the strategic direction that we want to take this company in,” FirstEnergy CEO Charles Jones said during an April 28 call to discuss first-quarter earnings. “We do not want to be exposed to commodity-exposed generation any longer than we have to be.”

In light of a $164 million first-quarter charge over unfulfilled coal delivery contracts, the Ohio-based utility holding company is eyeing a proposed nuclear subsidy from its home state and signals from U.S. Energy Secretary Rick Perry that federal policies toward coal generation could change.

The company reported earnings of $205 million in the quarter on revenues of $3.6 billion, including the charge related to coal delivery contracts. In the first quarter last year, the company earned $328 million on revenue of $3.9 billion.

Subsidiary FirstEnergy Solutions recently reached a $109 million settlement with BNSF Railway and CSX over long-term coal delivery contracts it terminated. The payments, guaranteed by FirstEnergy, are set to have begun on May 1, the company told the U.S. Securities and Exchange Commission in an April 27 filing. If that settlement is not completed — or a similar dispute with BNSF and Norfolk Southern Railway is not settled — damages could be much higher and lead FES to file for bankruptcy.

Coal supplier Tunnel Ridge also filed suit against First Energy subsidiary AE Supply over a terminated coal supply contract, which the company said could “be material.”

FirstEnergy executives are hopeful that a bill for a proposed “zero-emission nuclear resource program” will reach Ohio Gov. John Kasich’s desk by the end of June. The legislation would require electric distribution companies to secure the credits from qualified generation resources and recover the costs from ratepayers. Awarded according to nuclear output, the credits would gain FirstEnergy about $300 million/year.

“That amount in and of itself, I don’t think, is enough to necessarily avoid a FES bankruptcy,” Jones said. “It would be enough potentially for those assets to emerge from bankruptcy and for a reputable nuclear operator to be willing to take them on and run them forward.”

FirstEnergy touts the proposal as helping the state meet its energy goals, but critics say it is a bailout for the company’s nuclear plants. Ohio Citizen Action said the money should instead be invested in renewable energy and energy efficiency projects.

FirstEnergy owns the 889-MW Davis-Besse nuclear plant near Toledo and the 1,231-MW Perry plant near Cleveland, but the company wants to close or sell them.

Jones said that as the company assesses the implications of a FES bankruptcy, it is closely monitoring whether a new Energy Department study will lead to some type of support for coal plants.

Perry last month ordered his department to present by mid-June its evaluation of the premature retirements of baseload power plants, which is in part intended to determine whether energy markets adequately compensate the reliability benefits they provide. It is unclear what initiatives might flow from the process.

Perry’s memo mentioned “the market-distorting effects of federal subsidies that boost one form of energy at the expense of others” and said the study would provide “concrete policy recommendations and solutions.”

Jones said the Bulk Electric System is being overlaid on a congested and “not robust” natural gas delivery system, and problems with the natural gas system will flow to the electricity system.

FirstEnergy last quarter entered into an agreement to sell about 1,500 MW of AE Supply’s gas and hydro assets for $925 million, a deal expected to close in the third quarter. A $40 million agreement to sell property and assets at the Hatfield’s Ferry power station is expected to close in the third quarter of next year. Mon Power in March agreed to purchase the Pleasants power plant from AE Supply for $195 million.

May 2, 2017

PJM Markets and Reliability and Members Committees Briefs

Stakeholders Defer Vote on Regulation Revisions

WILMINGTON, Del. — John Horstmann of Dayton Power and Light expressed concern that PJM’s proposed regulation changes will have a “huge impact” on existing Reg D providers and noted that complaints have been filed at FERC opposing the changes PJM implemented in January. (See “New Regulation Rules Improving ACE Control,” PJM Operating Committee Briefs.)

Based on the potential issues, Horstmann made a motion at Thursday’s Markets and Reliability Committee meeting to defer a vote on the package until June, which would allow for the comment period at FERC to close. Members approved the delay in a 3.76 sector-weighted vote.

The package, jointly developed by PJM and the Independent Market Monitor, would replace the benefit factor with the “regulation rate of technical substitution,” and the effective megawatt calculation would be the area under its curve. The mileage ratio from the regulation performance credit would be replaced with the “marginal rate of technical substitution” (MRTS), which will be added to the regulation capacity credit. Bowring said later that PJM meeting rules prevented him from responding to comments from Horstmann that he believed to be inaccurate.

The 24-month transition period will have a minimum MRTS of .65 for the first year, followed by a floor of .5 for the last year. The minimum allowable participation threshold will be raised from 40% to 50%.

“The transition offer by PJM, while a nice gesture, [is] not really compensatory for existing Reg D providers,” Horstmann said.

CCPPSTF Charter Approved

The MRC approved the charter for the Capacity Construct/Public Policy Senior Task Force, declining to adopt language changes proposed by Market Monitor Joe Bowring.

Bowring suggested that one of the group objectives in the charter, which calls for “modifications to [the Reliability Pricing Model] that could accommodate/address both capacity construct objective and state actions,” wasn’t consistent with the charter’s mission to “ensure potential state public policy initiatives and Reliability Pricing Model objectives are not at odds.”

Bowring found no members willing to take up his suggested edits, and the charter passed with one objection and two abstentions.

The task force’s three meetings since its formation in January have revealed deep differences between stakeholders. (See PJM Capacity Task Force Debates the Value of Price Transparency.)

Stakeholders Push Back on Paying for Frequency Response

PJM markets and reliability committee frequency response — Schweizer | © *RTO Insider*

PJM’s David Schweizer presented a first read of the RTO’s plan to address FERC’s recent Notice of Proposed Rulemaking on frequency response. PJM’s proposal has suggested that it might consider compensating units for maintaining primary frequency response, even though the NOPR is silent on the topic. (See “PJM Wants to Study Frequency Response,” PJM Operating Committee Briefs.)

John Farber of the Delaware Public Service Commission staff took issue. “If we’re purchasing this premium [Capacity Performance product], it should include this primary frequency response,” he said.

He asked that the problem statement and accompanying issue charge include language that the compensation would be considered “if appropriate or necessary.” Schweizer said the documents were developed to allow dialogue on the topic while designing proposed solutions.

He said he will be seeking the Operating Committee’s approval on Wednesday and asked that any proposed changes be submitted as soon as possible.

Manual Changes OK’d

Stakeholders endorsed by acclamation two manual revisions:

Manual 14B: PJM Region Transmission Planning Process. The changes correcting wording in the baseline thermal analysis section to match analytical procedures and replace all occurrences of “special protection system” with “remedial action scheme” per a change to the NERC glossary of terms.
Manual 18: PJM Capacity Market. The revisions conform to FERC’s March 21 order tentatively approving PJM’s “enhanced aggregation” plan to allow seasonal capacity participation as CP resources. Stakeholders deferred sunsetting the Seasonal Capacity Resources Senior Task Force until the May meeting so they can be informed of any action on the seasonal capacity filing at FERC. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)

Members Committee

Members Endorse Pricing Revisions

The Members Committee endorsed revisions to PJM’s Tariff and Operating Agreement to address shortage pricing through the operating demand curve. (See “Shortage Rule Takes Effect amid FERC Silence,” PJM Market Implementation Committee Briefs.)

The committee also endorsed changes to Manual 15 regarding fuel-cost policies. (See PJM Fuel-Cost Policy Changes to Take Effect in May.)

Both changes had received substantial discussion in previous meetings, so members had little to say about them Thursday. Bowring reiterated concerns he has mentioned previously about PJM’s approach to handling fuel-cost policies.

– Rory D. Sweeney

May 2, 2017

Soapbox: ESA Explains Complaint on ‘Regulatory Dissonance’

By Matt Roberts

The Energy Storage Association recently filed a complaint with FERC seeking a review of PJM’s prior unilateral changes to its market for frequency regulation. Electricity markets are founded on the principle that practices affecting rates won’t be changed arbitrarily, which ensures fair treatment of companies that invest in and operate electric resources. This is particularly important to ensure new resources like advanced energy storage enter markets and increase competition. For this reason, the decisions impacting tariffs that PJM has made must be submitted for review by FERC.

PJM was the first market to use the near instantaneous response time and precisely controlled input and output of storage systems as a cost-effective tool to ensure short-term grid stability. PJM’s fast frequency regulation service (RegD) was designed for dynamic electric supply assets that are high-power, duration-limited and fast-responding, matching the moment-to-moment deviations of supply and demand to maintain the frequency of the electric grid. In contrast, PJM’s conventional frequency regulation service (RegA) continued to enable the participation of traditional electric supply resources, which have slower response times and ramp rates but can sustain service indefinitely.

As a result, more than 265 MW of advanced energy storage are currently deployed in PJM — nearly all of it competing in the regulation market. These energy storage systems have lowered costs and generated value for the millions of customers in PJM.

Regulation Market Certainty & Unilateral Changes

Over the course of 2015, larger system conditions were leading PJM to call on its energy storage resources to sustain longer-duration service regularly. Because RegD service was designed to be short-duration, PJM decided to make changes to the frequency regulation market while convening a stakeholder consultation process. In late 2015, PJM artificially capped how much RegD service can be provided, and in early 2017, PJM changed the parameters of RegD service, including ending its use for only short-duration needs.

The changes to the parameters of RegD service undermine its original purpose — to provide efficient response to short-term deviations of system frequency (typically measured in minutes). Keeping the grid in balance over longer periods — up to an hour or more — is the role of energy markets or, in emergencies, reserves. In effect, PJM has decided to rely on regulation resources to correct prolonged system imbalances rather than address their root causes. Additionally, the parameters of RegD service also determine how market participants are compensated, and these changes constitute a substantive modification to the actual rates.

Typically, when changes of a magnitude that impact market structures and compensation are being considered, the market operator submits these changes to FERC for review and approval. This review is an important step and is a legal requirement because it ensures that our nation’s wholesale electricity markets remain fair and accessible and that capable assets of all types are rewarded for their performance.

That is why ESA has submitted a Section 206 filing with FERC: to review the decisions made by PJM and enable the changes to RegD service to be considered as a formal tariff change. Moreover, without such review, nothing stops PJM from making changes of similar magnitude again in the future — creating significant uncertainty for energy storage market participants.

It is important to note that PJM staff were presented with proposals to address the broader system challenges that prompted the review of the frequency regulation market design — including proposals from ESA and its members — designed to meet PJM’s needs as the grid operator while enabling energy storage owners to adapt to new conditions.

After much discussion, these proposals from many different stakeholder groups were not put into place, and instead PJM decided to implement the rule changes opposed in our complaint — changes that have obstructed advanced energy storage system owners, operators and developers, and substantively impacted the market tariffs and resulting compensation.

The Path Forward

We very much agree with PJM staff and other stakeholders that the rules and parameters applicable to RegD service can continue to be improved and can also be adapted (or be a model for future markets) to address broader system challenges at PJM like overgeneration and the need for more fast-responding, medium-duration reserves on the system. To date, PJM has done an effective job of addressing these challenges and has not seen any significant change to relevant system reliability metrics (e.g., NERC Control Performance Standard scores) since RegD service was implemented.

However, the root causes of system conditions that led PJM to seek longer-duration response from regulation resources in the first place have not been explored. In effect, PJM has sought to solve a larger system reliability issue through the regulation market. It is important that PJM staff investigate what appears to be a consistent oversupply issue that is leading to the prolonged system imbalances — and specifically calling on RegD resources to be continuously charging over extended periods of time.

Further review by FERC will ensure that the broader influences of these changes on market tariffs and performance are considered holistically, and that PJM will continue to be a leading innovator in creating the model for competitive energy marketplaces. We look forward to working with PJM staff, regulators and a broader group of grid stakeholders on developing a better strategy for ancillary services and applications for energy storage, and by undergoing a more formal process, we can ensure that PJM customers don’t miss out on the ultimate objective — affordable and reliable energy, from increasingly sustainable sources.

Matt Roberts is executive director of the Energy Storage Association, the voice of the energy storage industry, representing manufacturers, utilities, grid operators, developers and technology companies, and working to promote the adoption of competitive and reliable energy storage systems. More info is available at www.energystorage.org.

May 2, 2017

PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition

By Rory D. Sweeney

WILMINGTON, Del. — Solutions for reducing uplift charges have been more than four years in the making, so PJM members at last week’s Markets and Reliability Committee meeting were largely unconvinced when financial traders argued that voting on the solution’s third phase was being rushed.

Financial stakeholders campaigned unsuccessfully for more than an hour to change the proposal.

Stakeholders then approved a package designed by PJM “to strike a balance between retaining the theoretical benefits of virtual trading while eliminating opportunities for virtual transactions to profit from the market without providing those benefits.” It limits incremental offers and decremental bids to “locations where the settlement of physical energy occurs,” where they compete directly with physical assets or trading hubs, where traders can take forward positions.

Up-to-congestion transactions would be limited to hubs, zones and interfaces — locations that are large aggregates. PJM said the change will address concerns that some UTC trades “do not benefit the market at a level commensurate with the profitability of the transactions.” (See “Members Approve Uplift Proposals,” PJM Markets and Reliability and Members Committees Briefs.)

Financial stakeholders mounted several efforts to influence the vote. They first called for deferring it until FERC has acted on Phase 2, which failed in a sector-weighted vote with 1.04 in favor. The MRC requires a two-thirds sector-weighted vote (3.33 out of 5). Only the Other Supplier sector — which includes financial traders — was in favor of the delay, with the other sectors almost unanimously opposed.

Attorney Ruta Skucas, who represents the Financial Marketers Coalition, called for the deferral, which was seconded by Joe Wadsworth of Vitol. Skucas said the proposal was changed significantly shortly before it went to vote and never received vetting at the Energy Market Uplift Senior Task Force, where the issue had been hashed out for years. The changes eliminated all but 41 nodes for UTCs, she said.

Wadsworth described the proposal as taking “a sledgehammer to the market,” saying the root issue was modeling errors that could be addressed by a more “surgical” approach, such as eliminating trading at locations where the day-ahead and real-time models can’t be aligned.

“When we start removing what traders can do in managing their portfolios on a day-ahead and real-time basis, we’re going to take away the uniqueness traders bring that leads to competition in the markets,” he said.

Bruce Bleiweis of DC Energy also supported a delay, saying he’s been involved with PJM for 21 years, and “this is the first time we’ve come to a rush to judgment.”

PJM MRC virtual transactions — Bleiweis (left) and Wadsworth | © *RTO Insider*

Other stakeholders disagreed.

“My clients would have a different opinion of that,” said attorney Susan Bruce, who represents the PJM Industrial Customer Coalition. “This is a solution that’s a long time coming.”

Direct Energy’s Jeff Whitehead took exception to the accusations of rushed voting.

“I believe this issue has seen its day in court. There are buses that are available to virtual traders on the system today … where there are modeling issues between the day-ahead and real-time market. And because those modeling issues ostensibly can’t be corrected by PJM, arbitrage opportunities exist that simply cannot be converged between the two markets,” he said. “If traders are simply trading with themselves at points that cannot converge, I don’t call that a market.”

“The purpose of the markets is to provide real power to real customers at the lowest possible cost,” said Joe Bowring, PJM’s Independent Market Monitor. “To the extent that virtual transactions are not contributing to that, it’s not appropriate to allow them to continue.”

PJM’s Adam Keech agreed, saying that rules for virtual trading are designed to have the “highest probability of adding the most to the system.”

PJM staff said it’s not clear when the proposal will be filed with FERC because contested filings require a quorum of commissioners to resolve, and the filing seemed likely to attract protest. Noha Sidhom, a financial trader who doesn’t participate in the virtual market, then proposed bifurcating the package into separate filings so that the noncontroversial portions — the limits on INCs and DECs — could be approved by FERC staff and implemented, while the UTC changes — which likely will receive protest — can wait until the commission has a quorum.

Stakeholders debated for some time whether that proposal should be considered prior to voting on the original package, and eventually determined that it should not. The original proposal passed with a 4.07 sector-weighted vote, with all but the Other Suppliers in support.

May 2, 2017

ERCOT TAC OKs Changes to CRR Calendar, Communications Rules

ERCOT’s Technical Advisory Committee last week unanimously approved changes to the ISO’s congestion revenue rights (CRR) activity calendar and its Nodal Operating Guide.

Both votes were conducted by email following an April 24 information session. The TAC canceled its regularly scheduled meeting due to a lack of voting items.

The first change updates ERCOT’s CRR calendar following the Board of Directors’ approval earlier in April of a nodal protocol revision request (NPRR). NPRR808 extended the CRR auction process into the third year forward — with one monthly and one long-term auction each calendar month — and revised the percentages sold in its long-term sequence. It also aligned modifying load zones to the timetable.

ERCOT tac congestion revenue rights crr — Power Traders | *SearchforEnergy.com*

“This should be a huge benefit to our market, and I’m excited to see it implemented,” Morgan Stanley’s Clayton Greer emailed his fellow TAC members after the vote.

ERCOT’s Carrie Bivens, manager of forward markets, said during the information session that the TAC’s approval was required by May 1 in order to be ready for the long-term auction that begins this fall. She said staff has not yet completed testing to ensure the credit monitoring and management system can handle the additional inventory.

“We believe we can, but the risk remains out there,” Bivens said.

The change to the Nodal Operating Guide (NOGRR167) revises it to be consistent with NPRR776, which was also approved by the board in April and aligns the protocol language with currently used verbal communication practices between transmission service providers, qualified scheduling entities and generation resources. The TAC had tabled NOGRR167 during its March meeting.

The committee is scheduled to meet again May 25.

– Tom Kleckner

May 2, 2017

No Consensus for SPP on Zonal Price Shifts

By Tom Kleckner

TULSA, Okla. — The issue of cost shifts within transmission pricing zones may soon surpass transmission upgrade credits as one of the most vexing problems facing SPP stakeholders.

Strategic Planning Committee Chair Mike Wise said last week that his committee has been unable to reach consensus on a more equitable means of determining cost shifts when new members join existing transmission pricing zones despite talks that began in January.

zonal price shifts spp — SPP’s Board of Directors and Members Committee | © *RTO Insider*

Kansas City Power and Light called for revising SPP’s policy after the RTO put the City of Independence, Mo., into the utility’s transmission pricing zone, increasing costs for KCP&L customers. (See Strategic Planning Committee to Continue Work on Tx Cost Shifts.)

The SPC held two special meetings during April — a month in which it doesn’t normally meet — trying to reach consensus on a staff proposal for a “symmetrical” cost/benefit analysis and a phase-in process for regulatory assets that evaluates the time value of money.

“During discussion, it became clear we still didn’t have agreement on staff’s proposal,” Wise told the Board of Directors and Members Committee last Tuesday. “It’s concerning to me that in the stakeholder process, we couldn’t come to a conclusion on this.”

The SPC last met April 20 in Dallas, where it voted on a motion to adopt part of staff’s proposal, rejecting calls to end the discussion entirely. The motion included a reference to “the understanding that the SPC does not endorse the outcome of any staff zonal placement decisions.”

“Basically, [we] just approved a staff process for communication of potential zonal placements,” KCP&L’s Denise Buffington said.

She said in January her company would likely file a complaint with FERC if the SPC doesn’t resolve the issue “to our satisfaction and in a timely manner.” Stakeholders did agree to the first steps in the process, which begin with the applicant transmission owner (ATO) notifying SPP of its intention to join the RTO. Staff would then request data from the ATO, study the zonal placement and cost analysis, and facilitate discussions between the ATO and the transmission zone’s incumbents.

Staff’s straw proposal suggested that the ATO be given an opportunity to negotiate cost shifts with the other transmission owners and network customers in the affected zone, with any resulting agreements filed with FERC.

If no agreement is reached, SPP proposed filing a cost-shift mitigation plan if the shift increased network customers’ baseline costs under Schedule 9 of the Tariff by more than 2.5%.

But staff now say there is little consensus for having a cost-shift threshold. Several stakeholders were adamant that they did not want SPP deciding what costs would be placed upon their customers.

“The problem is not with the mitigation, but the zonal placement criteria,” Buffington said. “The criteria lead to the zonal placement, and it’s the zonal placement that leads to cost shifts. The criteria that [dictate] the placement [are] the problem.”

Staff has suggested using the following criteria in determining whether to place the facilities in a new zone:

Whether the transmission facilities’ annual transmission revenue requirement (ATRR) is less than the minimum zonal ATRR benchmark;
The extent to which the transferring facilities substantively increase the SPP regional footprint; and
The extent to which the transferring facilities’ load received network service or long-term firm point-to-point service within existing zones prior to the transfer.

If the facilities are not placed in a new zone, staff would apply the following criteria in determining the existing zone in which to place the facilities:

The extent to which the facilities are embedded within an existing zone;
The extent to which the facilities are integrated with an existing zone; and
The extent to which the facilities load received network service or long-term firm P2P service within each existing zone prior to the transfer.

Buffington has been leading the work on a revision request (RR172) that she said would establish a bright line between the costs of legacy transmission and new facilities planned by SPP to protect customers from paying for facilities that were not jointly planned. That work has been on hold, pending the SPC discussions.

Wise agreed the SPC would return with another update for the July meeting in Denver.

“This cannot die where it is,” Board Chair Jim Eckelberger said.