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August 5, 2019

NEPOOL Markets Committee Briefs: July 30, 2019

The New England Power Pool Markets Committee last week continued to discuss impact assessments of ISO-NE’s proposed energy security improvements (ESI).

Analysis Group’s Todd Schatzki gave a presentation on additional preliminary results of a study on the risk premium on day-ahead energy option offers, as well as on two scenarios for the winter of 2025/26: a current market rules case, and one reflecting proposed ESI rules and expected market responses. (See “Assessing ESI Impacts,” NEPOOL Markets Committee Briefs: July 8-10, 2019.)

Unrecovered cost of actions taken to secure energy inventory will be compared to the change in net revenues associated with taking each action, Schatzki said, reading from the slides.

The risk premium depends on factors that affect the riskiness of the option position, including the expected marginal cost of production given a resource’s fuel inventory; the option strike price; and LMP volatility.

NEPOOL — Estimated cleared prices for day-ahead energy options under the high future case | *Analysis Group*

The analysis will consider three different winter scenarios for model year 2025/26: mild (based on 2016-17), moderate (2017-18) and severe (2013-14).

Analysis Group’s production cost model does not capture every market feature, such as congestion; commitment/start-up and min-load costs; and full EIS calculations, he said.

Schatzki said the results provide reasonable estimates of impacts, although they are preliminary, with some ESI elements and assumptions still being refined.

Analysis Group will present preliminary scenario results this month, and respond to stakeholder feedback and present a draft report in September, ahead of the RTO’s planned October compliance filing with FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

Margin for Uncertainty

ISO-NE Principal Analyst Andrew Gillespie gave a present ation providing additional detail on energy imbalance reserves (EIR) and replacement energy reserves (RER), two of the three day-ahead energy call options being proposed.

EIR awards will fill “known and needed” energy, akin to energy to meet demand in real time. RER and generation contingency reserves (GCR), the third call option, will supply energy that might be needed if a major contingency occurs, the equivalent to operating reserves in real time.

Combined, the three provide the “margin for uncertainty” in an increasingly energy-limited system, Gillespie said, referring to the presentation.

The RTO plans to allow imports across external interfaces to receive EIR awards, but imports would not be permitted GCR or RER awards because Northeast Power Coordinating Council standards require balancing authorities to provide its reserves using its own resources.

The RTO said resources with an EIR award should expect to be committed to meet the forecast for the next day.

“A unit with an EIR option awarded to meet the day-ahead forecast energy requirement should expect to receive a commitment instruction, which would be consistent with its start-up and notification times,” it said. “But it might not always be committed, if it has only an EIR option award, that is, if it has no day-ahead energy schedule.”

The day-ahead co-optimization will seek the most economical solution, meaning a unit that offers both energy and options could receive a day-ahead energy schedule only; an EIR award/schedule only; both a day-ahead and call option award; or no award.

The sum of any EIR option award and any day-ahead energy schedule within the same hour will be at least equal to the unit’s economic minimum, and not greater than the unit’s economic maximum, according to the RTO.

No M-DAM in October FERC Filing

The RTO’s vice president for market development, Mark Karl, on July 29 sent a me m o informing the MC that the grid operator will not include the multiday-ahead market (M-DAM) in its Oct. 15 compliance filing.

“The M-DAM design warrants further assessment and additional review with stakeholders before being proposed to the commission,” the memo said.

“While multiple day-ahead markets may have benefits to the region as the power system continues to evolve, we believe it would be prudent to spend the remaining time ahead of the Oct. 15 filing discussing the design and impacts of the new proposed day-ahead ancillary services,” Karl said.

The RTO plans to continue assessing the potential impacts of an M-DAM design and to discuss recommended next steps with stakeholders in 2020.

Time Limit on Fuel-security Resources

The RTO’s director of NEPOOL relations, Allison DiGrande, and its assistant general counsel, Christopher Hamlen, led a presentation on proposed Tariff changes to remove the potential for a fuel-security resource to be retained in the Forward Capacity Market for more than the two-year period allowed by FERC.

The proposed revision would clarify that a resource retained for fuel security will only be retained until the end of the fuel security need.

The RTO’s goal is to address reliability concerns through competitive solutions.

“When resource owners submit retirement bids and demand bids in the [Forward Capacity Auction], they are indicating their economic decision to exit the markets,” DiGrande said, reading from the slides. “Out-of-market retentions should be limited in scope and timing.”

Without a change, a resource retained for fuel security could be retained beyond the intended capacity commitment period, which further impacts the competitive processes in New England.

ISO-NE is requesting that the change become effective prior to the issuance of the Order 1000 request for proposals in December.

The RTO plans further discussion and final review of the proposed changes at the MC’s summer meeting in New Hampshire this month. The committee is expected to vote on the proposal in September before a vote by the Participants Committee on Oct. 4.

— Michael Kuser

August 5, 2019

Counterflow: NRDC Prescribes More Carbon Emissions

By Steve Huntoon

As in bridge, let’s review the bidding.

The Natural Resources Defense Council attacked PJM,¹ accusing it of suppressing renewable resources relative to other RTOs, wasting billions of consumer dollars in the process and contending, in effect, that a cheap and reliable zero-carbon future could be ours if entities like PJM would just mend their evil ways.

My responding column showed that reality is different.² PJM hasn’t obstructed renewable resources and, in fact, is outperforming its RTO brethren given the renewable cards the region was dealt. PJM’s capacity market (like other RTO capacity markets) doesn’t save uneconomic coal plants, doesn’t impose excessive costs on consumers, doesn’t suppress renewable resources and is a bulwark against bailout claims for uneconomic coal units that should retire.

NRDC ostensibly replied to my column.³ Not, mind you, to address much of what I said.

NRDC basically changed the subject. But its new claims are no more valid than the ones it made before, and its policy prescription is bigly counterproductive.

Natural Gas Plants Do the Heavy Lifting in Carbon Reduction

NRDC’s first new claim is that all retiring coal plants should be replaced with renewable resources because natural gas units won’t help reduce carbon emissions.

Specifically, NRDC says that carbon (CO₂) emissions will “plateau” if coal units are replaced with natural gas units, basing this on a claim that in PJM, carbon emissions increased in 2018 relative to 2017.⁴

In fact, carbon emissions per megawatt-hour in PJM decreased from 948 pounds in 2017 to 925 in 2018, another decline continuing the downward trend that I discussed in my column. This downward trend is shown in the graph below.⁵

Let’s look at that graph for something else: the decline in carbon emissions from the advent of the capacity market until now, going from about 1,225 pounds/MWh in 2008 to about 925 pounds/MWh in 2018, a reduction of 300 pounds/MWh.

Here’s a pop quiz question: How much of that 300-pounds/MWh reduction is attributable to wind and solar generation?

The answer is c, only 10% of the reduction is attributable to wind and solar generation.⁶ The reality is that new natural gas plants, and higher dispatch of gas plants generally, are responsible for 90% of the carbon-emission reduction in PJM.

This reality makes perfect sense. Remember that we’re not replacing average coal units with average natural gas units; we’re replacing old, inefficient coal units with new, efficient natural gas units. So it’s not just the rule-of-thumb 50% reduction in carbon; it’s more like a 65% reduction in carbon, along with a staggering 97% reduction in nitrogen oxides (NO_x) and a 99.8% reduction in sulfur dioxide (SO₂).⁷

Natural gas plants do the heavy lifting.

The PJM Capacity Market Works to Reduce Carbon Emissions

NRDC’s second new claim is that the PJM capacity market is flawed because the RTO could procure the targeted level of resources at a much lower price than it does.

NRDC gives a graphic example with a hypothetical clearing price of about $60/MW-day at the target reserve margin. NRDC’s example has the fatal flaw of its supply curve not actually intersecting the demand curve at that price.⁸

So it’s not a clearing price at all. ECON 101: Clearing price is where the supply and demand curves intersect. NRDC creates a fantasy.

In practical terms, NRDC is saying that PJM should procure the target reserve margin for about $60/MW-day — when the cost of new entry is about $300/MW-day.⁹

Under NRDC’s approach, new entrants would never recover the CONE. They will know that. Ergo, no new entry.

The inefficient old coal units would no longer be forced out by new, efficient natural gas plants. The coal plants hang on and continue polluting. Except for the small contribution from renewables discussed above, PJM’s downtrend trend in carbon (and other pollutants) would come to an end.

Does that sound good to you?

1- https://www.utilitydive.com/news/comparing-americas-grid-operators-on-clean-energy-progress-pjm-is-headed/557994/.

2- https://rtoinsider.com/counterflow-scary-wrong-139476/.

3- https://rtoinsider.com/pjm-market-design-hurting-clean-energy-140043/.

4- NRDC claims “carbon pollution in the region (and nationwide) increased year over year in 2018.” This is true (barely), but only in a literal sense because of an overall increase in PJM generation in 2018 relative to 2017.

5- https://www.pjm.com/-/media/committees-groups/task-forces/cpstf/20190726/20190726-item-06b-renewable-portfolio-standards-pjm-eis-and-generation-attribute-tracking-system.ashx (slide 3).

6- Wind and solar generation accounted for 2.8% of total PJM generation in 2018, http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018-som-pjm-sec8.pdf (page 356). So without that 2.8%, the 925-pounds/MWh emission rate in 2018 would have been about 950 pounds/MWh, which would have been a reduction of 275 pounds/MWh from the 2008 level. So wind and solar are responsible for a 25-pounds/MWh reduction, and natural gas plants — new plants and higher dispatch generally — are responsible for a 275-pounds/MWh reduction.

7- Using the Energy Information Administration’s eGRID data available here, https://www.epa.gov/sites/production/files/2018-02/egrid2016_data.xlsx (PLNT16 tab, columns PLCO2RTA, PLNOXRTA, PLSO2RTA), for a sample of five new natural gas plants (Newark, Woodbridge, Panda Liberty, Panda Patriot and Brunswick County) and five recently retired coal plants (Will County, Conesville, J.M. Stuart, Miami Fort and Bruce Mansfield).

8- Please note that what NRDC calls “Huntoon’s Alternative Supply Curve” actually does intersect with the demand curve, at a clearing price of about $300/MW-day.

9- The estimated net cost of new entry for the overall PJM region was about $320/MW-day in the last capacity auction. Estimated net CONE in the next auction is about $260/MW-day. Competitive markets continue to drive down costs.

August 5, 2019

National Labs Show Their Wares on Capitol Hill

The Department of Energy on July 24 celebrated its research collaborations with the electric industry at the annual National Labs Day on Capitol Hill, featuring remarks by members of Congress, a reception and displays on current projects. Here’s some of what we heard.

Utilities Learning to Work with Government

Sen. James Risch (R-Idaho) said he and many of his colleagues on the Select Committee on Intelligence are convinced “that the next large incident that we have in America is not going to be a kinetic attack; it’s going to be a cyberattack that can be just as devastating.”

Risch, co-chair with Sen. Dick Durbin (D-Ill.) of the Senate National Laboratory Caucus, said utilities have overcome their reluctance to cooperate with the federal government on cybersecurity.

“When I first got here [11 years ago] … they were very, very resistant to engage with the United States government as a partner in cybersecurity. … It was less than 36 months later that they were begging for us to help because they realized the magnitude of the cybersecurity threat — and also, by that time there had been some breaches. They realized how catastrophic it would be. So today we are very much partnering with the electric utility industry — and have to be — on cybersecurity.”

North American Energy Resiliency Model

Among the exhibits on display was one on the North American Energy Resiliency Model, which DOE plans to release in September. The model will input threats such as severe weather and cyberattacks and provide outputs such as the possibility of voltage collapse and gas pipeline outages.

Craig Miller, chief scientist for the National Rural Electric Cooperative Association (NRECA), which has advised the national labs on the project, was on hand to explain it to visitors.

Craig Miller of NRECA explains DOE’s North American Energy Resiliency Model. | © *ERO Insider*

Miller said it will provide grid planners and federal officials with an “integrated analysis” tool to help them determine the most cost-effective investments in resilience and reliability. “For example, should we harden against a wind storm in Florida, or is it more important to deal with earthquakes in Missouri with the New Madrid Fault?”

He called the new tool “a massive improvement” over the first attempt at developing a model after Hurricane Sandy in 2012. “There was a quick [effort] to pull it together. It was good, and lessons were learned, and some fine thinking was done. But this is a much more sophisticated, integrated model,” he said.

Bruce Walker, assistant secretary of DOE’s Office of Electricity, has been touting the model since after FERC rejected the department’s proposed rule to require “full cost recovery” for coal and nuclear plants with on-site fuel supplies.

But Miller said he is convinced the project has not been tainted by politics or special interests. “The work is being done by the national labs. And the national labs are fundamentally committed to doing honest analysis. They are at heart scientists and engineers,” he said.

Miller said NRECA, which represents more than 900 electric cooperatives covering two-thirds of the U.S. by geography, plans to offer recommendations on how to improve the tool after its release.

“Even though we only have 40-some million customers … the national infrastructure doesn’t operate without us,” he said.

DarkNet: Moving Critical Infrastructure off the Public Internet

The project has been tested through a partnership between the lab and Chattanooga, Tenn.’s municipal utility, EPB (formerly the Electric Power Board).

“We use our system as a test bed,” said James A. Ingraham, EPB’s vice president of strategic research. “We’ve had almost a five-year relationship with Oak Ridge. We have a 6,000-mile fiber optic network, along with over 1,200 automated switches and interrupters on our system, so the entire thing is automated. We think it’s the most automated electric distribution system in the world. So, it gives us a unique path to generate a lot of data instantaneously. So we’re doing cybersecurity, sensors, transformer design, renewable generation, energy storage, electric vehicle, microgrid design, microgrid networks. All of these things are going on in cooperation with DOE on our system.”

Ingraham said the utility built the fiber optic capacity when it modernized its 70-year-old system.

“We entered the computer age. We deployed 29 software platforms, state-of-the-art [supervisory control and data acquisition] and [emergency management system]. We deployed all the switching and automated metering, but you had to have the high-speed communications to make it all work,” he said. “We built a modern infrastructure and integrated energy and communications together. And people see the difference. We’ve eliminated 60% of our outage minutes in the last five years. People know when the power goes off, it’s going to come right back on as the switches reroute power.”

Sandia’s SCADA Simulator and WeaselBoard

Brian J. Wright demonstrated Sandia National Labs’ SCADA emulator, which is used in training and the evaluation of malware. “It’s kind of a sandbox environment. It also enables us to do hardware-in-the-loop” simulations, he said.

Wright showed a screen showing the CrashOverride malware that Russians hackers deployed in the December 2016 attack on a utility in Ukraine. (See Experts ID New Cyber Threat to SCADA Systems.)

“It had a specific module aimed at ABB’s power relay. So, we actually put it in as hardware-in-the-loop to this simulation.

“You’ve got a power simulation in the background informing emulated models of relays and power systems, a SCADA module, HMI [human-machine interface], everything in a substation. It allowed us to execute the malware and effect that physical relay as if we had built a real substation.”

Wright also demonstrated Sandia’s WeaselBoard, which allows operators to see and respond to physical and input/output (I/O) changes on their system.

“So, if I wiggle out an I/O module, you can see it’s alerted this card that sends a message to the HMI to alert that there is a module that’s been removed,” he said.

Wright said the WeaselBoard protects against malware such as Stuxnet, which the U.S. and Israel allegedly used to attack Iran’s nuclear weapons program — deceiving operators about what was actually going on in the physical process.

“What the WeaselBoard allows us to do is see the communications between cards and between the card and CPU, between the CPU and the network port out. It enables us [to know] the ground truth of what’s actually happening, so we can alert to anomalies in I/O, hardware changes, firmware changes.”

Why it called a WeaselBoard? “I am not privy to the history of the name,” he laughed.

Structured Threat Intelligence Graph

Rita A. Foster of the Idaho National Lab demonstrated an open source visualization tool called the Structured Threat Intelligence Graph (STIG) that can be used for understanding cybersecurity vulnerabilities.

It was funded by the California Public Utilities Commission under its California Energy Systems for the 21st Century (CES-21) program and included involvement by the state’s investor-owned utilities.

“Those lines are showing the relationship between attack patterns and indicators of compromise,” she said pointing to a fan-like pattern on her screen. “We’re going to query on this attack pattern and get all the other malware associated with that attack pattern, because one attack pattern has a lot of different malware associated with it. … You can tell that’s the attack pattern you want to look at because fixing that fixes a big, huge set of problems.”

An example of a Structured Threat Intelligence Graph analyzing a system infected with CrashOverride malware | *Idaho National Lab*

— Rich Heidorn Jr.

August 5, 2019December 12, 2023

Align Rollout to be Staggered

By Rich Heidorn Jr.

NERC has changed the scheduled rollout of its Align software program, with the Texas Reliability Entity and Midwest Reliability Organization turning the switch on “Release 1” in September and other regional entities joining in late October or early November.

“For the longest time, we were saying Sept. 19 was the day” for all the REs, Andrew Williamson, SERC Reliability’s director of reliability assurance, told SERC’s quarterly open forum July 29. “Based on feedback from the stakeholders involved, the [Compliance Monitoring and Enforcement Program] Steering Committee decided to take a slight change of plan.”

The deployment and training schedule for the remaining regions will be finalized in the next few weeks, Williamson said.

NERC concluded the phased deployment with a smaller population would reduce risks, allowing a reversal of the installation if critical problems are discovered. “We want to make sure that everything is functioning properly,” Williamson said.

He said the software developers have completed all system and process updates that arose during user acceptance (UA) testing in May and completed the second of three “change readiness assessments.”

The developer is continuing to prepare training materials and planning for additional UA and quality assurance testing. Training will begin “once we’ve got the code locked down, after we are assured that everything functions as designed,” Williamson said.

The Release 1 module will cover enforcement, mitigation and self-reporting functions. Monitoring functions such as technical feasibility exceptions, periodic data submittals and self-certifications won’t be live until Release 2 in 2020.

Williamson also provided an update on NERC’s inquiry into possible Chinese ties to BWISE Information Security, which NERC hired to develop Align.

Some registered entities raised concerns after BWISE was sold to SAI Global, an Australia-based company whose investors include a private equity fund managed by a Hong Kong company. (See NERC Investigating Chinese Tie to Software Vendor.)

Williamson told SERC members that NERC has concluded there are no concerns over BWISE’s ownership.

“I spoke to [NERC Chief Technology Officer] Stan Hoptroff, who’s in charge of the project, and he said that NERC worked with an outside government agency to go through and verify that there were no concerns with the ownership. It’s an Australian-based holding company that has significant ownership in Hong Kong. They’ve not been able to find evidence that there’s any issue or concern for the ownership of BWISE at this time,” Williamson said.

Williamson said Align is being hosted on single-tenant servers, by a Federal Risk and Authorization Management Program-certified cloud service provider and will require multifactor authentication to access. Documents, communications and data will be encrypted.

“It has to be secure,” Williamson said. “That isn’t an option.”

August 4, 2019

SPP Promotes Veteran Execs to SVP Positions

By Tom Kleckner

SPP last week announced the promotions of three longtime executives to senior vice president positions, though their areas of responsibilities will not change.

Barbara Sugg (information technology and chief security officer), Bruce Rew (operations) and Lanny Nickell (engineering) were all vice presidents over their departments.

Each of the new senior vice presidents has at least 20 years of experience with SPP. Rew joined in 1990 and was one of the organization’s original 14 employees, while Sugg and Nickell came on board in 1997.

CEO Nick Brown announced the promotions Thursday during SPP’s customary staff meeting following the Board of Directors meeting. Brown revealed his own retirement plans, effective April 2020, during the board meeting. (See related story, SPP’s Brown to Retire as CEO in 2020.)

“Each of these individuals has proven many times over that they possess the technical expertise, business acumen and leadership qualities that SPP needs to best serve our customers,” he said in a statement.

“Being promoted to senior vice president recognizes the importance of and dependency on IT and cybersecurity at SPP,” said Sugg, who oversees IT and telecommunications services to its members and establishes IT strategy and policies.

Rew has held several engineering and management roles at SPP, including serving as vice president of engineering. He is leading SPP’s Western expansion — which includes contract services for reliability coordination and an energy imbalance market — and is responsible for the grid operator’s market operations.

“This promotion is a recognition of the outstanding team of professionals I get the honor of leading on a daily basis,” he said. “I look forward to continued success in managing the operational opportunities ahead for SPP.”

Like Rew, Nickell has been vice president of both engineering and operations. He is responsible for transmission planning, tracking projects costs and statuses, and administering long-term transmission service and generator interconnection processes.

“SPP and the power grid face a future full of tremendous opportunities and rapid change,” he said. “It will be increasingly important for us to anticipate the exciting changes facing our industry and do so in a way that provides increased value for our members and their customers.”

August 4, 2019

NEPOOL Participants Committee Briefs: Aug. 2, 2019

ISO-NE COO Vamsi Chadalavada told the New England Power Pool Participants Committee that average day-ahead cleared physical energy during peak hours for July was 99.8% of forecasted load, up from 99.1% during June. “As far as I can recall, that’s about the highest that we’ve seen over the past few years,” he said. [Editor’s Note: Chadalavada approved his comments for publication after the PC meeting.]

The RTO prefers to fill its projected load through day-ahead awards because they maximize flexibility and minimize costs. Once the day-ahead market closes, the RTO’s choices are reduced because long-lead-time generators may not be available, resulting in greater reliance on more expensive, fast-start generators.

Daily net commitment period compensation (NCPC) payments for July were $2.7 million, up $1 million from June. Chadalavada said the payments were mostly the result of high loads in the Southeast Massachusetts/Rhode Island area and transmission outages on two 345-kV lines in Southern Maine.

Chadalavada said the SEMA/RI commitments are the result of a lack of a large generator in the load zone following the retirement of the Pilgrim nuclear plant.

“The need for second contingency protection in SEMA/RI is higher at loads greater than 20,000 MW,” he said.

Chadalavada also discussed the July 20-21 heat wave, which resulted in peak loads of more than 24,100 MW for the hour ending 18:00 on both days. The peak for the month, however, came July 30, when load hit 24,300 MW at HE 18:00.

Chadalavada said actual conditions on July 20 were close to the weather forecasts from the day before, but the weather forecasts the RTO relies on overestimated July 21 dewpoints by 3 to 4 degrees, representing 800 to 1,000 MW of load.

About 2,000 MW of generation self-scheduled on July 20 and 400 MW on July 21 to perform “Claim Capability Audits.” There also were some hours of negative prices in Northern Maine driven by New Brunswick imports and wind generation.

That, combined with deviations from day-ahead interchange and wind production schedules, resulted in LMPs ranging from $20 to $60/MWh.

On July 20, there were “substantial amounts of energy in real time that were not part of the day-ahead clear. So, the combination of all of these factors led to lower LMPs than maybe one would expect for a hot weekend,” he said.

Chadalavada also reminded stakeholders of a public meeting Sept. 12 in Boston on Regional System Plan 19. Stakeholder comments on the plan will be reviewed by the Planning Advisory Committee on Thursday.

PC OKs Revisions to Import Capacity Rules

The PC on Friday approved changes to the requirements for submitting external transactions for capacity imports, a move that ISO-NE said will streamline the procedure and align it with its Pay-for-Performance program.

The committee approved without opposition revisions to Market Rule 1, Manual M-11 (Market Operations) and Operating Procedure 9 (Scheduling and Dispatch of External Transactions), as recommended by the Markets Committee at its July 8-10 meeting. (See NEPOOL Markets Committee Briefs: July 8-10, 2019.)

The committee also approved revisions to OP-5 (Resource Maintenance and Outage Scheduling) over the objections of numerous generators, including Calpine, Dynegy and FirstLight Power. The changes, which were recommended by the Reliability Committee at its July 16-17 meeting, cleared the PC with 71.6% support. (See NEPOOL RC/TC Briefs: July 16-17, 2019.)

The changes to MR 1 and OP-9 were prompted by a new Enhanced Energy Scheduling (EES) software platform scheduled for implementation by October. They also include clean-ups to remove outdated provisions relating to coordinated transaction scheduling (CTS) and dynamic scheduling.

The RTO identified four primary changes:

Day-ahead and real-time energy offers will no longer have to be submitted with the same transaction;
A day-ahead transaction will not be required when the interface’s import transfer capability is zero;
Real-time transactions will no longer be required for capacity that wheels through NYISO to a CTS interface; and
All capacity imports backed by an external resource will have the same requirements pertaining to resource outages (i.e., to notify ISO-NE of outages and comply with the requirements of the native control area).

The RTO said the revisions to OP-5 are conforming changes to align with the revised market rule language for capacity imports. They will require market participants to notify the RTO if there is a reduction in capability that impacts the capacity supply obligation of the import resource(s).

Brett Kruse, vice president of governmental and regulatory affairs for Calpine, reiterated his previous opposition.

“We do not believe that external capacity should be counted as capacity unless it’s a specific generator with some form of firm point-to-point transmission or some other firm transmission product to ensure deliverability,” Kruse said in a statement he approved for publication after the PC meeting. “So even though that’s been longstanding [policy] — we allow that kind of stuff in New England — we’ll always vote against that.”

Consent Agenda

The committee also approved several measures on its consent agenda during its mee t ing, which lasted less than an hour.

Revisions to MR 1 and Tariff section 1.2.2 requiring solar resources to provide meteorological and operational data to support forecasting. It also consolidates in MR 1 the wind data forecasting requirements, which will be moved from Tariff Schedule 22.
Revisions to OP-8 to delete obsolete NERC provisions and align the procedure with Northeast Power Coordinating Council Directory No. 5.
Revisions to OP-13 and Appendix B to simplify references and make minor clarifications to terminology regarding under-frequency load shedding (UFLS) islands. Also clarifies compensatory load shed requirements and incorporates references to NERC’s regional reliability standard for under-frequency set points.
Revisions to OP-16 Appendix K regarding monthly ISO-NE updates and quarterly transmission planner updates to the short-circuit base cases. Reorganizes the document regarding generators and transmission owners.
Revisions to OP-2 Appendix C regarding the provision of contact information in requests for electronic copies of the equipment maintenance request form.
Revisions to OP-24 reflecting the change in Appendix C. The original diagram of relay outage locations was replaced with a list of transmission facilities for which TOs are reporting protection settings, characteristics, failures or degradation.
Revisions to OP-12 and Appendix D to clarify local control center actions for providing voltage schedules to generators.
Revisions to section I.2.2 of the Tariff to incorporate definitions for interconnection reliability operating limit (IROL) and system operating limit (SOL).

– Rich Heidorn Jr.

August 4, 2019

SPP Board of Directors/MC Briefs: July 30, 2019

DES MOINES, Iowa — SPP CEO Nick Brown last week told the Board of Directors and Members Committee that a recent FERC-NERC report on a 2018 cold-weather event confirmed the RTO’s position on MISO’s use of its system.

“I’m very appreciative of FERC and NERC inserting themselves in what was initially described as a contractual dispute,” Brown said during the July 30 meeting. “Significant clarification was needed, and we got that.”

The SPP Members Committee votes during the July 30 board meeting. | © *RTO Insider*

MISO uses a tie line in the Missouri Bootheel to link its Central and South regions. Under terms of a 2015 settlement with SPP, MISO is free to transfer up to 1 GW without compensating SPP and other parties, but it cannot exceed 2.5 GW or 3 GW, depending on the power flows’ direction.

On Jan. 17, 2018, unusually cold weather led to numerous outages and derates in the South. Entergy alone lost 11.6 GW of capacity, leading MISO to declare a maximum generation alert for the region. During the event, MISO exceeded its 3-GW north-to-south limit by 1.3 GW.

“It was one of the most significant operating events I’ve seen in my career,” Brown said.

SPP General Counsel Paul Suskie said that with the large number of contingencies on the regional grid, the report uses the term “N-many,” something the RTO’s veterans had never seen before.

FERC last September opened an inquiry, just the third it’s ever conducted. It released a copy of the report, done in partnership with NERC, on July 18. (See FERC Orders Cold Weather Reliability Standard.)

The report corroborates SPP’s position that any energy above the 1-GW transfer limit should be non-firm and as-available, staff said. They said the report noted MISO incurred risk in assuming it could transfer more than 1 GW across the seam.

In the report, FERC staff recommended NERC develop a standard on generation weatherization, the second time it has made that suggestion.

That work has begun, Brown said, and SPP has been asked to sponsor the effort. “We readily accept that opportunity,” he said.

The report included 13 recommendations for SPP, MISO and the other parties to the RTOs’ agreement (Associated Electric Cooperative Inc., Southern Co., Tennessee Valley Authority, LG&E and KU Energy, PowerSouth Energy Cooperative, and NRG Energy). Nine apply to SPP. The RTO has addressed four of them: perform periodic impact studies, analyze real-time voltage stability, conduct capacity and energy emergency drills, and consider deliverability to avoid stranded reserves. (See related story, “MISO Says Winter Standards Reasonable,” MISO Reliability Subcommittee Briefs: Aug. 1, 2019.)

Directors Lower Exit Fee to $100K

The board approved a Corporate Governance Committee (CGC) recommendation to lower SPP’s exit membership fee to $100,000, a 67% reduction from the current level. Load-serving entities would also be subject to an additional fee based on their net energy-for-load share of the RTO’s financial obligations and future interest.

FERC in April found the fee’s provisions to be unjust and reasonable and a barrier to market participation by non-transmission owners. The commission directed the RTO to eliminate the fee for members who are not TOs or LSEs. (See FERC Tells SPP to End Exit Fee for Non-TOs.)

The change still leaves SPP as the only grid operator with an exit fee not based on charging exiting members to cover their open market positions.

“SPP is still unique in having an exit fee. In my mind, the problem with the exit fee is it’s divorced from the costs driven by membership,” said Enel Green Power’s Betsy Beck, referring to meeting costs and staff time.

Beck said market costs should be borne by all market participants and not just members. “I certainly agree membership is important, but as the market evolves, there need to be pathways for others interested in being engaged,” she said.

“Where SPP is different [is that] membership matters,” Suskie responded. “When you’re a member, you truly have influence over what comes before the board.”

Paul Suskie explains SPP’s response to FERC’s decision on the exit fee. | © *RTO Insider*

When asked by Beck whether FERC would accept the $100,000 fee, Suskie noted that the commission approved its $300,000 fee in 2006.

“I’m sure your organization and others will protest,” he said.

The board also approved a recommendation that eliminates the exit fee as part of a compliance filing and language defining LSEs and non-LSEs. Staff proposed combining existing language in different Tariff sections to define LSEs as any member that satisfies either definition.

SPP has requested a rehearing of FERC’s decision but was granted a compliance extension to Aug. 1.

“By making this filing, we’re not challenging the ruling,” Suskie said. “We still have an obligation.”

Staff met the deadline by making the new exit fee (ER19-2523), compliance (ER19-2522) and LSE-definition (ER19-2524) filings.

Altenbaumer Delivers VATF, SPC Updates

Board Chair Larry Altenbaumer told the board and members they will likely see final recommendations from his Value and Affordability Task Force (VATF) during the October cycle of meetings.

He said the task force is paying special attention to “SPP’s overall performance in providing value” and that it intends to bring everything together by October. “We’re trying to get some consensus,” said Altenbaumer, who chairs the group.

To that end, the VATF has been divided into three sub-teams that are meeting separately from the full group:

Budget, led by Evergy’s Darrin Ives, focusing on budget, staffing and IT costs;
Process, led by NextEra Energy Resources’ Holly Carias, engaged in project approval and prioritization processes; and
Mission/Strategy/V, led by Golden Spread Electric Cooperative’s Mike Wise, concentrating on organizational group efficiencies and defining, measuring and communicating affordability.

The group, which was formed in January, is finalizing its definitions of affordability and value, determining the criteria for evaluating the sub-teams’ action plans, and updating communication plans on SPP’s value.

Altenbaumer also updated the board and members on the Strategic Planning Committee, which he also chairs. As part of its effort to develop a strategic vision, he said, the committee has used stakeholder feedback to draft a list of strategic initiatives that SPP should “actively pursue.”

Expanding the RTO’s footprint and implementing the Holistic Integrated Tariff Team’s (HITT) and the VATF’s recommendations top the list. Other proposed initiatives include adding services within SPP, focusing on cybersecurity and addressing energy storage technologies, integrating the rush of renewable energy and exporting renewables.

“At present, SPP doesn’t have a normal vision,” Altenbaumer said. “This is something we’d like a new consideration for the organization.”

Under its current timeline, the SPC will deliver its strategic plan to the board in July 2021.

SPP to ‘Beef Up’ Engineering Staff

CEO Brown said during his regular president’s report that SPP has decided to “beef up” its engineering analysis staff to address the backlogged generation interconnection queue, “one of the highest areas of discontent of our members and customers.”

“We have begun receiving numerous letters from congressmen and governors, begging us to do more and commit more resources,” Brown said.

OMPA’s David Osburn comments as Director Bruce Scherr listens. | © *RTO Insider*

He said recent changes to SPP’s interconnection process — a new three-phase study process and changes to eligibility for financial security refunds — have given the RTO pause to “look very hard at our resources.” (See FERC OKs New SPP Interconnection Process.)

“In this particular situation, the cost to the customer in the GI queue will go down, the administrative fee paid by members will go down [and] the administrative overhead will be spread over a larger group,” Brown said.

A side benefit will be increased customer engagement, Brown said, pointing to recent turnover in the engineering group. “They would rather do the technical work they were trained to do than manage the GI queue,” he said.

Brown also said the CGC he chairs will meet Aug. 22 to consider nominations for seven expiring seats on the SPC and Members, Finance and Human Resources committees. He said the incumbents had said they “desire to continue to serve” but welcomed additional nominations.

Basin’s Christensen Joins SPC

The consent agenda was passed without dissent. It will result in:

The approval of Basin Electric Power Cooperative’s Tom Christensen for the open TO position on the SPC. Christensen replaces Basin’s Mike Risan, who has retired.

The 2020 operating plan, which details SPP’s planned work for the upcoming calendar year after being vetted and approved by the Finance Committee and SPC. Next year’s plan focuses on providing market and reliability services in the Western Interconnection, implementing the HITT’s recommendations and developing a proactive response to known and emerging cyber threats.

Lowering a previously approved Missouri project’s costs from $40.4 million to $31.6 million. Evergy’s Kansas City Power & Light, KCP&L-Greater Missouri Operations and Westar Energy companies are responsible for the 345-kV voltage conversion project.

— Tom Kleckner

August 4, 2019

MISO Reliability Subcommittee Briefs: Aug. 1, 2019

CARMEL, Ind. — At first blush, MISO agrees with FERC’s recent recommendation that NERC develop cold weather reliability standards — but it is still reviewing the commission’s report and the possible implications.

“We do consider it a fair report, with reasonable recommendations,” MISO Reliability Subcommittee liaison Mike McMullen told stakeholders at last week’s RSC meeting.

“It’s relatively new out there, so MISO is still evaluating,” he added.

Among other recommendations, FERC called for new studies that emulate a realistically stressed grid, better communication on the effects of ambient temperature on generation and transmission lines, improved freeze protection measures on generation, and clearer emergency protocols around MISO’s regional dispatch transfer limit between its Midwest and South regions. (See FERC Orders Cold Wea ther Reliability Standard.)

The commission issued the recommendations after investigating an atypical cold snap in MISO South on Jan. 17, 2018, that led to higher-than-expected demand and caused MISO and SPP to seek voluntary load reductions, nearly forcing load shedding. (See related story, “RTO Applauds FERC, NERC Report on Cold Weather Event,” SPP Board of Directors/MC Briefs: July 30, 2019.)

MISO to Share Cyberattack Data with Feds

MISO is now operating under new rules that will allow it to share nonpublic data with the federal government if it finds itself or its members under a cyberattack.

The RTO last year proposed to share more information on significant cyberattacks with the Department of Homeland Security and other federal governmental agencies when it deems it appropriate. (See MISO Tariff Changes Target Cybersecurity Data Sharing.) FERC approved the new data-sharing strategy in June, despite Exelon’s contention that MISO should specify the types of attacks and narrow the federal agencies receiving reports (ER19-875).

MISO Director of Incident Response and Systems Recovery David Rosenthal said in spring that the RTO anticipates using the information-sharing protocol “rarely, if ever.”

Executive Director of Controls and Engagement Joe Polen told the RSC on Thursday that MISO will only share data on a limited basis and that only its corporate information security officer or cyber director can make the determination.

“We don’t share that information unless we absolutely have to,” Polen explained. “MISO hopes to never need to use the additional data-sharing practices.”

Polen also said MISO can terminate the agreement with Homeland Security at any time.

Northern Indiana Public Service Co.’s Bill SeDoris asked whether members will be notified if MISO shares their information.

“If we do have an event where we have to share information, we will contact the members and let them know what was shared,” Polen responded.

However, MISO legal staff at the meeting said there may be some instances where DHS may want the RTO to delay notifying members for a reasonable period while it investigates and addresses a cyber threat.

MISO Reworking Outage Penalty Conditions

MISO is putting a finer point on the penalty exemption policy under its stricter generation outage scheduling rules.

In June, MISO pitched a plan to exempt resources from accreditation penalties if the length of a submitted outage remained within 10% of the originally scheduled outage window, providing wiggle room to either reduce or lengthen outages. (See “Outage Exemption Talk Ongoing,” Stakeholders: MISO System Fix Too Late for Summer.)

MISO will now allow outage reductions of up to 20% of the original window without triggering a full revaluation of the outage’s impact on expected capacity margins. Those seeking to increase the length will be required to submit an entirely new outage request.

The penalty exemption rules are part of a new policy requiring generators to schedule planned outages 120 days in advance in order to be categorically exempt from possible accreditation penalties; the new process was approved by FERC in late March (ER19-915).

Shift operator Trevor Hines said more members have been in contact with MISO to discuss the nuances of their planned outages since the outage rules were enacted.

“We have been receiving more calls and communications, and we recommend those continue as you approach situations that you need help with. … Those calls have gone very well the last few months,” Hines said.

2 Emergency Warnings in June

June was mostly cooler than usual for MISO, although the South region experienced tight operating conditions and near-emergency calls twice during the month.

Average load for the month was 77.8 GW, lower than the 84.5-GW average a year earlier. The 107.8-GW monthly peak set on June 27 also fell far short of last June’s 121.6-GW peak. During a July Informational Forum, Rob Benbow said average temperatures for the month were lower than normal and 8 degrees lower than in June 2018. Lower loads and fuel prices brought average prices down to $23.07/MWh, 27% year-over-year decrease.

MISO said its reliability, markets and operational functions performed well over the month.

However, MISO issued a maximum generation warning for South on June 3 when load and forced outages crept upward and transmission outages stranded some generation. South was also the subject of a separate maximum generation alert on June 20, again prompted by forced generation outages and transmission outages from storms the night before.

“We were able to manage our way through those conditions,” Benbow said.

MISO has issued real-time generation notifications three months in a row, including a May maximum generation emergency declaration, a June maximum generation warning and conservative operations instructions during a mid-July heatwave.

During the RSC meeting, WPPI Energy economist Valy Goepfrich asked MISO to begin distinguishing in its reports the locations of its maximum generation notifications, based on the Midwest, South or footprint-wide regions.

Telephones and Hot Topics

MISO may change its control room phone system and is asking members for their recommendations and experiences with their own systems. The RTO is circulating a nine-question survey to members to collect information on other phone plan options.

Finally, MISO’s upcoming Hot Topic discussion during September Board Week in St. Paul, Minn., will focus on transformative changes taking place in the energy industry and how the RTO could ease the transition for its member companies. Members are expected to bring their ideas on what future services they may require of MISO during the Sept. 18 conversation.

Director of Market Strategy and Design Scott Wright said he believes the talk will in part center on the trends MISO laid out in its first Forward Report issued earlier this year. (See New MISO Report Starting Point for Major Grid Change.) He said he expects to hear conversation on the need for improved ramp capability, increasing two-way power flows on distribution — and possibly transmission — systems, and how MISO can best manage transactions between the wholesale and retail level.

— Amanda Durish Cook

August 4, 2019

CPUC Program ‘Runs Afoul’ of PURPA, Court Rules

By Robert Mullin

In a decision that could boost small solar development in California, a federal appeals court last week struck down a state program that sets the terms by which investor-owned utilities must contract with alternative energy suppliers.

The decision by the 9th U.S. Circuit Court of Appeals found California’s Renewable Market Adjusting Tariff (ReMAT) program violates the Public Utility Regulatory Policies Act by capping the volume of energy that utilities must purchase from qualifying facilities and setting contracts at a market-based rate rather than one based on a utility’s avoided cost. The ruling affirmed a district court opinion.

“The district court observed that ‘despite the complex regulatory and factual background’ in this case, ‘the key legal issues turned out to be straightforward.’ We agree,” Judge M. Margaret McKeown wrote in the appellate panel’s opinion.

The case arose when Winding Creek Solar, a QF seeking to develop a 1-MW solar facility in Lodi, Calif., contested the ReMAT program, which the California Public Utilities Commission implemented in 2013 to set a market-based rate for energy generated by QFs.

After Winding Creek unsuccessfully challenged ReMAT at FERC, it filed suit in the U.S District Court for the Northern District of California, which issued a summary judgment in favor of the company but declined to grant its preferred remedy of receiving the initial $89.23/MWh contract price offered under ReMAT at the program’s inception. The QF then appealed that decision to the 9th Circuit for further review.

‘Essentially an Auction’

The legal questions over ReMAT came down to its design, which was intended to bring an element of competition to QF contracting while providing suppliers with access to a market.

Under the program, QFs in a given utility service territory are placed into a queue on a first-come, first-served basis. Every two months, in what the court described as “essentially an auction,” the utility offers to contract with QFs at the front of the queue at a predefined price. QFs are free to accept or reject the contract, and those choosing the latter can hold their place in the queue until the next round of offerings two months later.

The CPUC caps the volume of energy the state’s three large investor-owned utilities must buy through the program at 750 MW, which is divided among the IOUs based on their share of peak load. Each utility is additionally allowed to subtract from its share any energy that it purchases under other CPUC programs.

The Winding Creek facility would be sited in the territory of Pacific Gas and Electric, which is obligated to purchase about 150 MW of energy under ReMAT, divided equally among “baseload,” “non-peaking as-available” and “peaking as-available” generation. Winding Creek falls under the last category.

The court pointed out that PG&E is obligated to purchase no more than 5 MW of energy from each category over a two-month period, allowing it to halt contract offers after reaching the caps.

The ReMAT program also functions as a kind of dynamic price-setter for QF contracts. While the CPUC initially set a QF contract price of $89.23/MWh for peaking as-available generation, ReMAT prices can adjust every two months based on the willingness of QFs to accept contracts at the price offered during the previous bidding interval. If QFs collectively offer less than 1 MW of energy during a two-month period (and there are at least five unaffiliated QFs in the queue), the price rises for the next interval; if QFs supply more than 5 MW, the price declines. In cases when QFs supply 1 to 5 MW, the price remains unchanged. Prices adjust based on a formula provided by the CPUC.

When Winding Creek was accepted into the ReMAT program in 2013, it was not placed near the top of the queue and did not receive the initial $89.23/MWh price. By the time it received an offer in March 2014, the contract price had fallen to $77.23/MWh, which the developer rejected because it could not operate the facility at that price.

Two Wrongs

The 9th Circuit first took issue with ReMAT’s cap on the amount of energy utilities must purchase from QFs, calling it impermissible because it violates PURPA’s “must-take” provision.

“As a result [of the cap], a utility could purchase less energy than a QF makes available, an outcome forbidden by PURPA,” the court found.

The court further determined that ReMAT’s pricing scheme “runs afoul” of PURPA’s requirement that utilities contract with QFs at their avoided cost rate (ACR). While acknowledging that state agencies have flexibility in calculating that rate, the court said “the ReMAT price, which is arbitrarily adjusted every two months according to the QFs’ willingness to supply energy at the predefined price, strays too far afield from a utility’s but-for costs to satisfy PURPA.”

The court went on to reject the CPUC’s argument that its other PURPA program, known as the “Standard Contract,” provides QFs a sufficient alternative to ReMAT. While that program offers an ACR based on a six-variable formula, the court found that three of the six “are impossible to determine at the time of contracting.”

“The Standard Contract violates PURPA because it fails to give QFs the option to calculate avoided cost at the time of contracting,” the court said.

The court pointed out that PURPA mandates that QFs be given a choice of calculating the avoided cost at either the time of contracting or time of delivery.

“The bottom line is that two wrongs don’t make a right. Because neither option offered by the CPUC is PURPA- compliant, California’s regulatory scheme is pre-empted by federal law.”

But the appellate court also did not provide full satisfaction to Winding Creek, agreeing with the lower court’s decision that it would not be offering “equitable relief” by granting the QF a contract at ReMAT’s initial $89.23/MWh price.

“Indeed, it would be inappropriate to order a non-party to contract with Winding Creek under a modified version of the very program the court had just determined to be pre-empted by federal regulation,” the court found. “It is not the court’s job to fashion a new contract to Winding Creek’s liking.”

August 4, 2019

MISO Firming Up 1st SATA Ruleset

By Amanda Durish Cook

MISO is nearing its goal of an October FERC filing to solidify its first, limited set of storage-as-transmission assets (SATA) rules.

“There’s a number of complicated issues, and we can’t make promises … but I think we’re making good progress,” MISO Director of Planning Jeff Webb said of the filing target during an update at a Reliability Subcommittee meeting Thursday.

Webb said MISO staff are currently drawing up Business Practices Manuals to pair with its Tariff filing so the rules can be implemented soon after approval.

The RTO is also promising another, more comprehensive set of SATA rules in the future that would allow for concurrent use of resources as both transmission and generation.

One Wisconsin battery project is so far striving for SATA treatment in MISO’s 2019 Transmission Expansion Plan (MTEP 19). (See MTEP 19 Could Yield First MISO SATA Project.)

Webb said owners of storage projects selected in the MTEP will enter into transmission owner agreements and become registered TOs, if they aren’t already.

MISO is holding firm that it’s not yet ready for storage that can simultaneously provide transmission services and offer into the energy market.

“It’s rather more complicated when it’s earning two revenue streams,” Webb said.

He also said MISO considers the discussion closed on DTE Energy’s proposal to allow non-TOs to own and operate SATA. (See MISO Limits Storage as Transmission Asset Ownership.)

But Webb also called MISO’s filing a “placeholder” for a more exhaustive approach that allows electric storage to function as both transmission and energy. For now, though, the aim is to “keep it simple,” prohibiting SATA from participating in markets, thus drawing a line between how storage is treated under FERC Order 841 and how it will be considered as transmission in the MTEP study process.

“We’re trying to get to a place where, yes, you may have a battery in MTEP … and be able to also earn market revenues,” Webb told stakeholders. “We fully expect that will be the end result.”

WEC Energy Group’s Chris Plante asked how MISO will account for the limited, three to four hours of discharge that batteries can provide in reliability planning.

Webb said the duration of storage discharge will be a key consideration in the transmission planning process.

“If we don’t have the confidence that a storage device can ride through a peak load period, we just wouldn’t pick it,” Webb explained.

Customized Energy Solutions’ David Sapper said he still wasn’t convinced that a storage device managing transmission constraints won’t have impacts on the energy market.

“It is important to establish what it should and shouldn’t be used for,” Webb responded.

MISO will hold final stakeholder discussions on its SATA filing at Planning Advisory Committee meetings on Aug. 14 and Sept. 25.