Page 1216 – RTO Insider

August 5, 2019

SPP Regional State Committee Briefs: July 29 & Aug. 5, 2019

DES MOINES, Iowa — SPP’s Regional State Committee on Monday endorsed a report on wind-rich areas and several recommendations related to the RTO’s effort to improve its planning processes, cost-allocation methodologies, and market products and services.

The RSC failed to reach an agreement on the Cost Allocation Working Group’s report and its recommendations when the group brought them forward during the committee’s regular quarterly July 29 meeting.

SPP — The RSC meets July 29. | © *RTO Insider*

The proposed actions were included in the Holistic Integrated Tariff Team’s (HITT) package of 21 recommendations, which the Board of Directors approved on July 30 despite stakeholder pushback. (See related story, SPP Board Approves HITT’s Recommendations.)

The CAWG recommended:

Decoupling the Schedule 9 and Schedule 11 transmission pricing zones, allowing for a potential larger Schedule 11 pricing zone;
Evaluating the byway facility cost-allocation review process; and
Considering a future study of the generator injection rate.

Several RSC members suggested July 29 that further evaluation is needed before decoupling the zones, while others argued against the “all-or-nothing” approach and the complexity of the work ahead.

Given a week to think about the CAWG’s recommendations, the committee approved them without discussion during a conference call Monday by an 8-1 vote, with one abstention and one not voting. The same motion was rejected by a 6-5 margin on July 29.

Texas Public Utility Commission Chair DeAnn Walker cast the one opposing vote and Oklahoma Corporation Commissioner Dana Murphy abstained. Both were outspoken in their opposition to the recommendations the week prior, saying they couldn’t agree to everything in the report.

During that discussion, Kansas Corporation Commissioner Shari Feist Albrecht asked whether the RSC would be abdicating its authority over cost allocation by not voting on the recommendations.

SPP — RSC President Kim O’Guinn, Arkansas PSC | © *RTO Insider*

RSC President and Arkansas Public Service Commissioner Kim O’Guinn responded by saying, “I think we have provided plenty of input to the board.”

“More than you realize,” cracked SPP Board Chair Larry Altenbaumer.

The CAWG’s Cost Allocation in Wind-Rich Areas report determined that SPP’s current cost-allocation methodology “and/or rate recovery mechanism in zones with a high proportion of generation relative to zonal load is not reflective of cost-causation principles.”

John Krajewski, representing the Nebraska Power Review Board, said the CAWG identified three potential rate approaches for further review, which will be folded into the HITT work: generation injection, zone consolidation and a “surgical approach.” The latter, recommended by Chairman Emeritus Jim Eckelberger, would provide a narrow process through which costs for specific projects between 100 and 300 kV “can be fully allocated on a regionwide basis.”

“It had more appeal than the broad byway cost-allocation project,” Krajewski said.

RSC Ponders Joining OMS on Tx Incentives Comments

During the conference call, the RSC also debated whether to join onto the Organization of Tx Incentives NOI Brings Calls for Broader Reforms.)

SPP — Nebraska’s John Krajewski explains the wind-rich report. | © *RTO Insider*

The OMS comments included a section on interregional planning, drawing the RSC’s interest. SPP stakeholders in particular have been frustrated with the lack of interregional projects with MISO.

The draft comments are “not fully formed, but they give you an idea of where the OMS is leaning,” Albrecht said.

She said she saw this as an opportunity for the OMS-RSC Seams Liaison Committee, on which she serves, to “emphasize the states’ interest in interregional planning issues.”

“But if the RSC wants to join [the comments], we can do that,” she said.

Albrecht said the OMS plans to post the draft comments Aug. 15, in advance of an Aug. 22 meeting to finalize the comments. The RSC penciled in a meeting on Aug. 23 to review the final document and decide whether to join the comments.

FERC provided an Aug. 26 deadline for reply comments.

Regulators Cancel 2020 Safe Harbor Review

During its July 29 meeting, the RSC did endorse the CAWG’s recommendation to leave the safe harbor eligibility criteria and limits untouched and not to conduct a limited review of the waiver criteria in 2020, given the working group’s HITT responsibilities. Instead, the group will perform a full review in 2021, the first of “at least one every five years.”

Missouri Public Service Commission economist Adam McKinnie said the CAWG did not “see any problems” with canceling next year’s review. He said the working group determined there was “no significant new information” since the end of the 2018 comprehensive study.

The RSC began requiring more limited reviews when a full study in 2016 found no changes were needed. Subsequent safe harbor reviews have come to similar conclusions, leaving some to wonder whether they are worth the effort. (See SPP RSC Leaves Safe-Harbor Thresholds Unchanged.)

“I told my [CAWG] representative that the review is not a good use of their time,” Walker said, in pushing for a full review at least once every five years.

The reviews are conducted to determine whether modifications should be made to the thresholds used to determine what project costs should be borne by load-serving entities making long-term transmission service requests (TSRs).

SPP’s aggregate transmission service study process combines into a single study all long-term point-to-point and designated network resource requests received during a specified time period. The RTO splits the costs of transmission projects between the entire SPP footprint and the LSEs purchasing transmission service for designated resources — those used to meet the LSE’s capacity margin requirement.

The safe harbor exempts LSEs from upgrade costs when a TSR meets the aggregate studies’ waiver criteria, which include:

Wind generation not exceed 20% of designated resources.
TSRs for designated network resources must have a minimum five-year term.
Designated resources may not exceed 125% of forecasted load.

The RSC also approved its 2018 audit report. Auditing firm Landmark CPAs reported no disagreements with management that could be significant to the report’s financial statement.

— Tom Kleckner

August 5, 2019February 12, 2025

NYISO Management Committee Briefs: July 31, 2019

The Analysis Group will delay the release of a carbon pricing study previously expected to be completed this month in order to perform additional analysis at the request of the NYISO Board of Directors, CEO Rich Dewey told the Management Committee on Wednesday.

The board wants to ensure the study captures all the impacts of the Climate Leadership and Community Protection Act (A8429) signed by New York Gov. Andrew Cuomo last month, Dewey said.

The new law requires 70% of the state’s electricity to be generated by renewable resources by 2030, nearly quadruples the state’s offshore wind energy goal to 9 GW by 2035 and targets making the electric system carbon-neutral by 2040. It also doubles distributed solar generation to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030. (See Carbon Pricing Study Navigates Shifting NY Landscape.)

Several stakeholders pressed Dewey on whether completion of the study is now open-ended or whether it would be delayed a few weeks or six months.

Dewey confirmed the study will be delivered within a few weeks, then taken to the board before being delivered to stakeholders, which he promised to make happen “as soon as possible, because I understand the intense interest for stakeholders.”

“Our carbon pricing proposal is the most effective way to meet the state’s clean energy goals,” Dewey said. “We won’t do it without the state on board, but we don’t have a deadline, except for the NYISO budget,” adding the ISO will decide on related funding in the six weeks remaining before its 2020 budget and project portfolio finalized.

A study released last month by the nonprofit Resources for the Future (RFF) indicates a $63/ton carbon price could drive clean energy penetration to as high as 64% of the state’s resource mix by 2025, “well on the way” to the 70% requirement for 2030. (See Study: Carbon Adder Supports NY Clean Energy Goals.)

In response to a question from the MC, Dewey said NYISO does not plan to bring the RFF study to the stakeholder group, explaining that an earlier version “was in front of stakeholders about a year ago.”

Generation and Tx Perform Well in Heat

New York’s generation and transmission infrastructure performed well during the July 18-21 heat wave, Operations Vice President Wes Yeomans said.

“Heat indexes in New York state were very high over those days,” Yeomans said. “So far, this summer we’ve had five days over 30,000 MW … and so far the peak load was on a Saturday, which would be unique and unusual if it holds.”

NYISO’s load has topped 30,000 MW on five days so far this summer. The peak so far came on Saturday, July 20, when load reached almost 30,400 for the hour ending 17:00. It “would be unique and unusual” if a Saturday remains the peak, the ISO said. | NYISO

NYISO said in May that it expected to have adequate resources on hand this summer to meet slightly above-normal demand, with 42,056 MW of capacity available to meet a forecasted peak of 32,382 MW. (See NYISO Reports Grid Ready for Summer.)

The ISO’s projected summer peak is 1.5% above the 10-year average and exceeds last summer’s actual peak of 31,861 MW, recorded on Aug. 29 (and the 2017 peak of 29,677 MW), but it is down from the 2018 peak forecast of 32,904 MW.

Yeomans said that since adding low-voltage facilities, “there have been far fewer out-of-merit actions in western New York.”

No New Cost-of-service Study

As it has in the previous two years, the MC voted not to conduct a new cost-of-service study later this year that would have informed a decision on whether to modify the 72% withdrawals/28% injections cost allocation formula in Rate Schedule 1 (RS1).

NYISO staff recommended a new study in order to consider the impact of the most significant market design changes to be implemented since 2005, including the integration of renewable resources, the adoption of a distributed energy resource roadmap and the effort to integrate and optimize energy storage.

The current RS1 allocation, with rebates provided for recoveries from non-physical transactions, is based on a consultant study that garnered about 67% support from the MC in July 2011 and was scheduled to be effective for a minimum of five years, from January 2012 to December 2016.

— Michael Kuser

August 5, 2019

Appetite for Renewables Growing in Penn. Legislature

By Christen Smith

Democratic lawmakers in Pennsylvania appear more hungry than ever to transition the state’s electricity consumption to 100% renewable energy, though it’s unclear whether the current plan will make it past the General Assembly’s Republican gatekeepers.

Companion proposals — House Bill 1425 and Senate Bill 630 — would phase out fossil fuels statewide by 2050, potentially making Pennsylvania the latest in a wave of Mid-Atlantic states to adopt aggressive clean energy targets to combat climate change. Some 21 of the 26 senators and 79 of the 102 representatives needed to pass the bills have signed on as cosponsors, including four Republicans in the Senate and seven in the House of Representatives.

“Embracing the clean energy revolution is the right thing for Pennsylvania,” said Sen. Tom Killion (R), prime sponsor of SB 630. “Passing this legislation will help ensure Pennsylvanians enjoy clean air and pure water for decades to come and the corresponding economic benefits of the clean energy economy.”

“When it comes to Pennsylvanians committing to a just transition to 100% renewable energy, I recommend we follow the old aphorism that ‘people who say it can’t be done shouldn’t interrupt those who’re already doing it!’” said Rep. Chris Rabb (D), prime sponsor of HB 1425. “When enacted into law, this bill will codify the goals and means by which we will make these vital aspirations a reality by 2050 — because our commonwealth’s brightest future must start now. And I have 99 colleagues in the Pennsylvania General Assembly who agree that the future is green!”

Still, Rabb and Killion have some convincing left to do as the legislature’s fall session nears — and even then, it will still be a heavy lift to get the bills onto the floor for a vote.

Unlike its neighbors to the east and south, Pennsylvania’s natural gas production from its Marcellus Shale region thunders on and keeps energy prices so low in PJM that other generation sources seek subsidies just to keep up. The Pennsylvania Independent Oil and Gas Association (PIOGA) forecasts that shale gas will supply 30% of the nation’s gas demand by 2030 and generate $1.8 billion in state and local tax revenues by next year.

State Republicans have long been champions of natural gas — especially House Speaker Mike Turzai, the most prominent beneficiary of the industry’s campaign donations, with $128,000 to his name as of the last election cycle. In June, he reiterated the caucus’s commitment to capitalizing on the state’s gas production, saying, “Pennsylvania has already benefited immensely from the boom in natural gas extraction, and House Republicans are dedicated to building on those gains rather than endangering them.”

Turzai also frequently touts the cumulative $16.2 billion reduction in utility bills over the last decade, 30% drop in carbon dioxide emissions and tens of thousands of jobs created — all from the shale gas revolution.

Mike Straub, spokesperson for the House Republican Caucus, told RTO Insider on Monday that he hasn’t heard anyone mention HB 1425, but that doesn’t mean renewable energy isn’t important to its 110 members.

“I think there’s been support for renewable energy in many different forms,” he said. “It’s always a balancing act to ensure Pennsylvania’s energy portfolio includes the right mix [of resources] that is best for consumers, employers and the economy.”

While Senate Majority Leader Jake Corman (R) doesn’t carry the same clout among industry donors, some 55 gas wells remain active in his district, according to state records. It’s a tiny share — less than 1% of Pennsylvania’s nearly 28,000 active wells — but large enough to give the Centre County Republican pause when it comes to proposals that might challenge its economic foothold.

As recently as June, he criticized Democratic Gov. Tom Wolf’s call for a severance tax on natural gas that would replace the impact fee currently dispersed to the state’s 67 counties for economic reinvestment.

Nick Troutman, spokesperson for the Senate Environmental Resources and Energy Committee, said a vote on HB 630 is unlikely in the near future.

“More discussion needs to take place on the federal and the state levels. Over the next 20 to 30 years, energy demand is expected to rise significantly, and renewable energy production is not without its challenges,” he said. “We need a diverse energy portfolio, which includes fossil fuels, in our energy mix.”

Political Will

Even if Republican leaders allow a vote, however, PIOGA Executive Director Dan Weaver called switching to renewables in just 30 years “impractical.” He said natural gas will remain an “important” sector of the resource mix because combined cycle plants provide efficiency and reliability at a cheap price.

“Pennsylvania’s businesses and families will benefit from energy production options based on market forces, and that includes obtaining more energy in the future from renewable sources,” he said. “We do not support overly generous government subsidies of any kind that benefit some sources at the expense of others, nor do we support increased taxes on sources that put them at a competitive disadvantage.”

David Masur, executive director of PennEnvironment, argued that the bills’ collective 100 cosponsors mean it’s time for “a real dialogue.” He said six states have approved similar policies in the last 12 months, including “purple states” like Maine and Nevada, “paving that path for Pennsylvania to do it as well.”

“When we look back on who had the political will to do what it takes to protect our planet from the far-reaching negative effects of global warming, this will be the group of legislators recognized for their work in Pennsylvania,” he said. “Because the question is not, ‘Do we have the technological ability, the financial wherewithal, or the work ethic to tackle climate change?’ The only question is, ‘Do we have the political will?’”

The House returns to session Sept. 17, though Straub said the legislative calendar is still taking shape. Some energy bills will be on the agenda, he noted, but not necessarily HB 1425. The Senate convenes the following week.

August 5, 2019February 12, 2025

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.

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, 2019October 21, 2025

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, 2019January 26, 2025

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

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.