Page 1190 – RTO Insider

October 6, 2019

Renewable Proponents Outline MISO Planning Wish List

By Amanda Durish Cook

Clean energy advocates are asking MISO to make comprehensive changes to its transmission planning to help ensure the region can continue an uninterrupted shift toward renewable resources.

Among the requests from the Environmental and Other Stakeholder Groups sector: that the RTO revise its future scenarios, synchronize interconnection and planning studies, and re-evaluate interconnection upgrade cost allocation.

Renewable projections under current futures used in MISO’s Transmission Expansion Plan (MTEP) are “far too conservative,” Clean Grid Alliance (CGA) consultant Natalie McIntire said in an interview with RTO Insider.

MISO renewables — CGA’s Beth Soholt in June | © *RTO Insider*

“If you look at the four futures, only the most aggressive future is an accurate depiction of what’s happening today,” CGA Executive Director Beth Soholt said. “In other words, we’ve blown past those futures. So, MISO isn’t planning for the future, much less planning for today.”

The four futures estimate that MISO’s resource mix will consist of a 15 to 35% share of renewables by 2033. But stakeholders for months have been criticizing those estimates as seriously underestimating the widespread adoption of renewables. Several have said the RTO’s predictions are resulting in inadequate new transmission projects and leaving renewable developers with prohibitively expensive interconnection upgrades as system patches. (See More MISO Members Join Call for Tx Planning Change.) MISO has said its large interconnection queue means that the “scope and costs of network upgrades are expanding.”

MISO is now developing a straw proposal on new futures development for stakeholder review at an Oct. 17 workshop. The new futures will be in place for MTEP 2021, and the RTO will use a slightly updated version of its MTEP 19 futures for its 2020 cycle of transmission planning.

The Union of Concerned Scientists’ Sam Gomberg said he generally thinks the four scenarios have been thoughtfully constructed.

“In terms of structure, I think the futures don’t need to look radically different. The structure is sound,” he said.

It’s the content that concerns him.

“The futures are not living up to this ‘bookend’ framing,” Gomberg said, using an oft repeated word among MISO planners. “They’re not planning in the futures for what is coming.” He said the RTO needs to consider both widespread renewable participation and a “carbon constraint umbrella.”

Members of the Environmental sector have also called for one or more futures to model carbon regulations.

“Maybe I’m living in my own environmental echo chamber, but if the political winds shift, what we’re talking about is getting to 0% carbon emissions by 2050. Decarbonizing the electricity sector by 2050 is a real possibility,” Gomberg said.

The growing grassroots momentum to address climate change also can’t be ignored, Gomberg said, with or without a federal government willing to draft a carbon cap policy.

“These [policy] conversations slowed down, and MISO staff for a couple of years maybe felt like they had a justification to slow down and wait for some kind of carbon cap,” Gomberg said. “We can’t be sure what shape it’s going to take … but we can be very sure that’s there going to be some type of limit. I don’t want MISO to be caught off-guard on the pivot.”

Increasing Complexity

“MISO likes to plan around certainty,” Soholt noted, adding that the RTO accounts for state statutes and orders from state commissions but could be overlooking municipal and corporate renewable commitments and carbon targets, as well as utilities’ request for proposals.

“There’s all this mismatch of things that MISO isn’t taking into account. We’re always going to be in a chicken-and-egg situation if MISO doesn’t expand their bookends and reflect reality,” she said.

It’s not simply a matter of waiting for the expiration of the investment and production tax credits to expire so transmission planners can get back to business as usual, Gomberg said.

“The numbers that I’m seeing say wind and solar are still going to be the cheapest resources out there. There’s going to be other developers ready to fill that void,” he said.

MISO might be underestimating in its future how electrification might stimulate the currently flat demand for energy, McIntire added. “If not right now, we see that demand might grow in the next five to 10 years.”

Gomberg also said MISO should more closely evaluate the effects of nuclear plant retirements in the 2030-2035 time frame as plant owners are faced with choosing between a license extension or retirement.

Soholt expressed concern that MISO’s renewable estimates could lead to a system “funded on the backs of interconnection customers, which naturally raises questions of who can reap the benefits of such projects.”

McIntire said interconnection customers don’t receive financial benefits from transmission investments comparable to the rate of return that the RTO’s transmission owners receive.

“They’re not getting benefits commensurate with the costly transmission upgrades interconnection customers are having to construct,” she said. “And if load ultimately pays, we want the transmission planning and interconnection process to consider what’s most cost efficient for ratepayers. We would suggest that constructing a transmission grid with a whole lot of lines paid for by interconnection customers is not fair or efficient. Comprehensive transmission planning with much more realistic future scenarios is a more cost-effective way to build out the MISO grid.”

“It’s not just a little tie-line; it’s not just a substation upgrade,” Gomberg said, stressing that interconnections have now become regionally beneficial to the system.

McIntire pointed out that MISO also separates interconnection upgrades from other transmission project types in such a way that cost allocation is the burden of interconnection customers only.

That existing process is blind to the fact that many others in MISO benefit from interconnection upgrades, she said.

“We all know transmission will bring a variety of benefits to a variety of beneficiaries,” McIntire said, calling for a “more holistic” cost-benefit analysis on interconnection upgrades.

Synched

McIntire also said MISO’s interconnection upgrade studies and transmission planning studies should move on the same schedule and draw on the same study assumptions.

“There’s a bit of a timing disconnect in that we have generator interconnection studies on one track and MTEP planning studies on a different track,” she said.

McIntire said MISO is in a position where it could reject a congestion-relieving transmission project, believing the congestion will be taken care of through an interconnection upgrade attached to a proposed generation project. However, interconnection upgrades can disappear as developers withdraw project proposals from the queue. McIntire said it’s not fair to assign the costs for an interconnection upgrade simply based on which of these study processes finishes first.

“Because those processes are done in silos, they’re cutting some projects off at the knees,” Gomberg said. “The left hand isn’t talking to the right hand to some degree.”

McIntire also said transmission planners should be looking to the queue as an indicator of where developers will site new resources.

“The queue is a good indicator of what will occur,” CGA Regional Policy Manager Sean Brady agreed.

“It’s always been that not all the projects in the queue get built. That’s a fair thing to say,” Gomberg said.

Though not perfect, the queue is a “strong indicator” of where resources will get built because often another developer comes in with plans in the same area, Gomberg said. The fact that all of the projects in the queue don’t get built shouldn’t be used as an excuse to say there’s too much uncertainty to move forward in the planning process, he added.

October 6, 2019February 12, 2025

NYISO Study: Carbon Charge to Help NY Climate Goals

By Michael Kuser

RENSSELAER, N.Y. — A NYISO study released last week finds that pricing carbon into the ISO’s wholesale markets will help New York achieve its clean energy goals — the most ambitious in the country.

“Carbon pricing advances the value of New York’s leadership role,” said Sue Tierney of Analysis Group, co-author of the final carbon pricing report. “Assuming New York endorses this idea, NYISO will adopt it and make a filing with FERC.”

Tierney summarized the carbon pricing report to the Installed Capacity and Market Issues Working Group (ICAP/MIWG) after its release was delayed a couple months to perform additional analysis on the impacts of the Climate Leadership and Community Protection Act (CLCPA), as requested by the NYISO Board of Directors. (See NYISO Management Committee Briefs: July 31, 2019.)

Signed into law in July by Gov. Andrew Cuomo, the CLCPA requires 70% of the state’s electricity to be generated by renewable resources by 2030, raises its offshore wind energy goal to 9 GW by 2035 and requires the whole economy to be carbon-neutral by 2040. The law also doubles the distributed solar generation goal to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030.

A newly created Climate Action Council will implement the measures needed to meet the environmental targets.

Emission rates for electricity generation in New York (2000–2018) | NYISO

The report’s authors contend that in order for the electric sector to help decarbonize New York’s other economic sectors, which are responsible for 83% of carbon emissions, on the “aggressive” time frames set out in the CLCPA, the “power system will need to adjust to vastly different levels and shapes of electricity demand while simultaneously adding clean energy resources on a scale and pace unseen in recent years in the state (and perhaps not since the mid-20th century).”

The effort will require “every effective means possible” to achieve reductions at the lowest possible cost, the report says.

The report notes that renewable resources covered about 20% of load-serving entities’ demand for electricity in 2018, with 80% coming from hydroelectric plants. The CLCPA will require renewables to cover 70% of LSE demand by 2030.

“A price on carbon in wholesale markets can provide a signpost to low-cost compliance pathways and preserve the fundamental wholesale electricity market structure that encourages operational efficiency and minimizes consumers’ investment risks,” according to the report.

No Heresy

Tierney also discussed the report with NYISO CEO Rich Dewey during a Thursday teleconference with reporters.

“Competitive electric markets are a strong and proven platform from which to leverage innovation, and we look forward to collaborating with the state on the exciting and important work ahead,” Dewey said in a press release ahead of the event.

“You can’t really leave any tools in the toolbox if we are going to achieve these goals,” he said during the conference, the Times Union reported.

But hours before that feel-good event, Tierney faced NYISO stakeholders in what seemed at first to be a session of the Spanish Inquisition, formed to sniff out any sign of unorthodox methodology or belief.

Twenty minutes into her presentation, she was still practically on the first page of a 35-page summary.

“You guys are ridiculous,” Tierney said in jest, to which one of the stakeholders replied that, on the contrary, they were behaving moderately compared to their usual ways.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, objected to the process of skipping the stakeholder feedback sessions promised by NYISO and jumping straight to a final report.

Mager also raised concerns about the scope of the study being changed without notice to stakeholders or an opportunity for them to provide feedback on the revised study scope.

Tierney deferred to Rana Mukerji, NYISO’s senior vice president for market structures, who assured Mager and other stakeholders that the ISO still welcomed their feedback and would consider if additional work on the study was necessary. And because the stakeholders did not have time to read the report — as it was issued only that morning — Tierney would be back to answer more questions during the week of Oct. 21, he said.

Assuming enormous public health and ratepayer benefits, there will be out-of-pocket costs that can be attributed to the cost of complying with CLCPA, Tierney said. “The study looks at net benefits of carbon pricing. The implication is that there would be near-term costs for long-term savings and benefits.”

Representing New York City, Couch White attorney Kevin Lang expressed concern about the effect of those near-term cost increases in the city, where the closest renewable energy option is offshore wind, which requires state subsidies, at least for now.

“Initial wholesale costs are going to be higher in New York City, so the state may have to enact other policies to mitigate those effects,” Tierney said.

Mark Younger of Hudson Energy Economics said, “If you don’t act [to implement carbon pricing], there will be other costs associated with that inaction,” referring to various harmful effects of climate change.

Asked how much a carbon charge would help incent new renewable energy projects, Tierney said that financing projects based on renewable energy credits (RECs) and zero-emission credits (ZECs) “is hard to come by, as banks prefer to look at market energy prices,” and that when the market price reflects the social cost of carbon, the market will be more efficient.

Guessing Game

“We don’t know what the Climate Council will do, what the Public Service Commission will do [and/or] what the Department of Environmental Conservation will do in terms of adopting a social cost of carbon,” Tierney said. “We imagined a robust policy toolkit, assuming the kinds of things that already exist, such as long-term REC contracts, performance standards and the like.”

Tierney said it might help for policymakers and stakeholders to look at the study as a cost-effectiveness analysis rather than a benefit/cost analysis, and that pricing carbon is a cost-effective way for the state to meet its environmental goals.

“If the New York wholesale market does not align its price signals with the new law, it will not be efficient,” she said. “This is not a modeling report. We describe the modeling results of others, and we calculate a present market value of some of those results.”

Outlook for zero-carbon electric resources | Analysis Group

The study stuck to the electricity sector, but there’s “going to be a lot of work” for New York to get to 70% renewable energy by 2030, she said.

“One of the features of the current construct is that RECs and ZECs are paid on a load-ratio share,” said David Clarke, director of wholesale market policy for Power Supply Long Island. “So rather than those zones whose carbon emissions would be increased most by nuclear closures paying for the ZECs, there is an implied acknowledgement that keeping nuclear plants open to reduce carbon is a statewide goal with statewide sharing of costs. We are paying a load-ratio share downstate.”

He asked whether the study considered how carbon pricing will change the zonal allocation of ZEC and REC costs.

“Qualitatively but not quantitatively,” Tierney said. “We looked at it in terms of increased risk to consumers and felt that rather than relying on long-term contracts for RECs and ZECs, carbon pricing would reduce risk by shifting it away from consumers. … And carbon pricing also would help consumers avoid the costs of buyer-side mitigation.”

October 3, 2019

MISO Cracks Door on Long-term Tx Planning

By Amanda Durish Cook

MISO officials on Tuesday signaled their willingness to entertain a request by state regulators to develop a long-term transmission package to accommodate growth of policy-driven generation resources.

But they also made clear they’re not ready commit to the idea.

MISO and its stakeholders late last year opened a debate on whether the RTO should launch a second regional transmission package similar to 2011’s multi-value project portfolio. Clean energy supporters argued a coordinated approach to transmission development would ensure that proposed renewable projects could be built in a cost-effective manner. (See MISO Stakeholders: New Blueprint Needed for Tx Planning.)

The Organization of MISO States has been clear for months that it wants the RTO to begin analyzing another long-term transmission package. In June, it released a set of principles intended to advise MISO on its long-term planning. In a letter accompanying the principles, OMS President Daniel Hall said several drivers, including “many ongoing state-level activities related to investments in future generation, energy efficiency and distribution systems” precipitate the need for MISO to examine its long-term transmission needs.

“Given the timeline associated with infrastructure planning and development, and the need to cost-effectively maintain reliability in light of the rapidly evolving fuel mix, the OMS finds value in moving forward in a timely manner to assess system needs and identify potential solutions,” Hall wrote to MISO CEO John Bear.

OMS’ principles include fostering a transparent stakeholder process to identify cost-effective projects and heeding the changing resource mix, reliability requirements and viable non-transmission alternatives. (See OMS Outlines Long-term Tx Planning Principles.) However, some MISO South members said the principles were too obvious to be helpful.

MISO took a first step to address the issue when it convened a workshop Wednesday to discuss its current long-term planning processes. While RTO officials gave little indication whether they are considering mounting a second regional package, staff did touch on what has changed after eight years.

MISO Executive Director of System Planning Aubrey Johnson clarified that the workshop was not meant to discuss specific long-term project proposals.

“We don’t have any lines on any maps. We don’t have any projects in mind today,” he said.

Currently, MISO’s long-term transmission planning is not developed on a routine cycle but performed on an as-needed basis “in response to major changes in public policy or the industry,” RTO adviser Joe Reddoch said.

MISO principal adviser Matt Tackett said electricity flow patterns are getting more difficult to predict year to year as central baseload generators retire and distributed resources pick up slack.

“I think we might be entering an era where dispatch and availability are more volatile,” he said, noting that distributed resources and electric vehicles can become mobile supply and loads, making them challenging to pin down

He said it’s no longer necessarily the case that MISO will know “where generation is and where the energy is coming from.”

Tackett also said the shifting resource mix also means that MISO shouldn’t simply assume that aging transmission lines need to be rebuilt in their original locations.

Minnesota Public Utilities Commission staff member Hwikwom Ham asked MISO to begin quantifying the costs of not pursuing transmission projects that exhibit long-term benefits.

“I think not doing something is not an answer because that has clear economic effects,” he said.

In response to stakeholders’ questions on whether MISO’s ongoing renewable impact study might spur long-term transmission investments, Johnson said the study shouldn’t be considered a “lead-in” to a long-term transmission package. Instead, he said the study might be used to inform inputs should MISO independently decide it needs a long-term planning cycle.

October 3, 2019

Pennsylvania Governor Signs RGGI Executive Order

By Christen Smith

Pennsylvania Gov. Tom Wolf (D) signed an executive order Thursday directing the state’s Department of Environmental Protection to join the Regional Greenhouse Gas Initiative (RGGI) — a move that left the legislature’s Republican majority bewildered and outraged.

Wolf instructed the department to craft rules that “abate, control or limit carbon dioxide emissions from fossil-fuel-fired electric power generators” and establish “a carbon dioxide budget” on par with the other nine RGGI states no later than July 31, 2020. If approved by the commonwealth’s Environmental Quality Board, Pennsylvania would join fellow PJM states Delaware and Maryland.

Pennsylvania RGGI — Pennsylvania Gov. Tom Wolf | *PA.gov*

“Climate change is the most critical environmental threat confronting the world, and power generation is one of the biggest contributors to greenhouse gas emissions,” Wolf said Thursday. “Given the urgency of the climate crisis facing Pennsylvania and the entire planet, the commonwealth must continue to take concrete, economically sound and immediate steps to reduce emissions. Joining RGGI will give us that opportunity to better protect the health and safety of our citizens.”

According to RGGI, it has reduced its members’ power sector CO2 pollution by 45% over the last 14 years and provided $2.31 billion in lifetime energy bill savings. Participating states — either through regulation or legislation — cap power plant emissions and auction off credits to generators on a quarterly basis, who purchase these allowances as proof of compliance. The proceeds return to participating states for reinvestment.

“We know that we can’t complete this process in a vacuum,” Wolf said. “The conversation we’ve begun over the past year needs to continue if we are going to craft regulations that fit Pennsylvania’s unique energy mix, while making sure that the transition to a cleaner energy mix doesn’t leave behind workers and communities our state has relied on for decades to produce its power. And it will take buy-in from the legislature to ensure we’re protecting Pennsylvanians from the increasing effects of the climate crisis.”

Firm Opposition

But many of the state’s lawmakers want nothing to do with RGGI.

Republicans in both the House of Representatives and Senate challenged Wolf’s unilateral move as an overreach and argued that the program is nothing more than a tax increase that harms the state’s thriving fossil fuel industry and — ultimately — ratepayers. Pennsylvania is second only to Texas in natural gas production and provides nearly 20% of national demand — a figure expected to double by 2040.

“We strongly disagree with Gov. Wolf’s continued practice of go-it-alone approaches that are unhelpful in working cooperatively to move our commonwealth forward in a way that best represents the interests of all Pennsylvanians,” House Republican leadership said in a joint statement published Thursday. “Our state is not an autocracy, and one-sided decisions as significant as this leave out the important voices of Pennsylvania workers, communities and families whose livelihood is built upon important sectors of our energy economy.”

The Republican leaders went on to tout the natural gas industry’s impact on electricity bills and greenhouse gases “without burdensome regulations” and cited federal data that show a 14% decline in carbon emissions from the proliferation of gas across the country and 30% in Pennsylvania alone.

“We believe the executive branch cannot bind the state into multistate agreements without the approval of the General Assembly, and we plan to execute the fullest extent of our legislative power on behalf of the people of Pennsylvania,” the letter concludes.

Republican leaders in the Senate said they would only consider policies that further reduce greenhouse gases in a manner consistent with their caucus’s own energy principles — including preserving the state’s energy portfolio, protecting the existing workforce, keeping electricity rates low and implementing any carbon-reduction plan through “an appropriate legal manner.”

“Throughout the last 10 years, we have supported many initiatives that have resulted in Pennsylvania’s greenhouse gas reductions that eclipse the CO2 reductions in RGGI states,” Senate President Pro Tempore Joe Scarnati and Majority Leader Jake Corman said in a joint statement. “As a net-exporter of electricity, we know that energy production is a vital part of our state’s economy.

“We expect that the legislature will have the opportunity to engage in this process, to make sure that any change in energy policy ensures a balance between safeguarding the environment, preserving energy jobs and protecting ratepayers.”

Republican Sen. Gene Yaw, chairman of the Environmental Resources and Energy Committee, chimed in on Twitter, where he expanded upon another one of his caucus’s energy tenets: requiring current RGGI members to “utilize all aspects of the state’s robust energy portfolio.”

“It’s clear to me we have very little in common with [New York], [New Jersey] and the New England states,” he said. “How can we have a common interest with them when they prohibit the importation of our gas? They thumb their nose at Pennsylvania gas and embrace and purchase gas from Russia!”

‘Display of Leadership’

Democrats, however, celebrated the governor’s decision, including Senate Minority Leader Jay Costa, who proposed his own cap-and-invest program over the summer to address carbon emissions. (See Pa. Dem Leader Pushes Cap-and-Invest Energy Plan.)

“Today’s executive order is a strong display of leadership from the governor on one of the most serious issues facing Pennsylvania, this nation and the world,” he said. “Leadership from the federal government is not coming on climate change, and we can’t afford to wait.”

DEP Secretary Patrick McDonnell said RGGI “represents a unique opportunity for Pennsylvania to become a leader in combating climate change and grow our economy by partnering with neighboring states.”

“As a major electricity producer, Pennsylvania has a significant opportunity to reduce emissions and demonstrate its commitment to addressing climate change through a program with a proven track record,” he said.

October 3, 2019

Coastal States Still Reign in Energy Efficiency Rankings

By Amanda Durish Cook

Coastal regions are picking up steam in implementing energy efficiency, while areas in Middle America are either stalled or backsliding, according to the latest annual ranking of states’ individual measures.

Massachusetts led the American Council for an Energy-Efficient Economy’s 13th annual State Energy Efficiency Scorecard for the ninth consecutive year. California came in a close second, while Rhode Island and Vermont followed in a tie for third place.

During a webinar Tuesday, ahead of the report’s release, ACEEE researcher and report author Weston Berg said Massachusetts’ lead is the result of “groundbreaking” building codes, emissions standards and appliance programs.

Energy Efficiency Rankings — 2019 state energy efficiency scorecard rankings | *ACEEE*

To rank the states, Berg said he and other researchers examined states’ utility regulations, building codes and transportation policy in 2018.

“Energy efficiency is sometimes overlooked as an invisible resource,” said Berg, adding that a strong energy efficiency strategy can help states meet emissions targets, reduce air pollutants, create jobs and reduce energy burdens in areas with tight supplies.

All told, states spent $8 billion on energy efficiency in 2018 and saved 27.1 million MWh — 0.73% of total retail electricity sales in the country, enough energy to power 2.6 million homes for a year, ACEEE said. However, that figure is 0.5% less than the 27.27 million MWh saved in 2017.

ACEEE Senior Director of Policy Maggie Molina said the scorecard allows state leaders to compare against each another and “spur some friendly competition.”

Molina said Maryland improved more than any other state in a year-over-year comparison, gaining ground — and three slots to a No. 7 ranking — through utility efficiency programs, stronger building energy codes, public transit funding and electric vehicle adoption.

Massachusetts Department of Energy Resources Commissioner Judith Judson said energy efficiency efforts are the single greatest factor in meeting the state’s 25% reduction goal in greenhouse gas emissions from 1990 levels.

“It’s not just about ranking us against each other … but to learn from each other on programs that really work,” Judson said.

Chris Rice, acting chief of staff of the Maryland Energy Administration, said his state rose in the rankings because of regularly updated building codes and the Em POWER Maryland initiative, which established energy savings goals on a per capita basis. Rice said the program is effective because it extends to low-income households.

“This is a very important aspect of our program: that everyone is served and able to participate in our program,” Rice said.

New York also maneuvered back into the top five this year thanks to adopting targets to shrink energy consumption by 185 trillion Btu by 2025 and procuring its electricity from 100% carbon-free sources by 2040.

“If states embrace robust energy-saving measures nationwide, Americans can slash greenhouse gas emissions by 50% and deliver more than $700 billion in energy savings by 2050,” ACEEE Executive Director Steve Nadel said in a release.

Kentucky and Ohio lost significant ground this year, according to the report. The report also put North Dakota and Wyoming behind all other states.

Kentucky’s downgrade is the result of regulators in 2018 “drastically cutting” most consumer-facing energy management programs by Kentucky Power and other utilities, Berg said.

Berg said Ohio is set to backslide on efficiency with the passage of its nuclear bailout bill, which also lowers the state’s existing energy efficiency savings standard for utilities from 22% to 17.5% by 2020. Berg said the bill will cause lower investment in renewables and energy efficiency, and it’s “very unlikely” efficiency programs will continue in the future because utilities are already on the verge of meeting the goal. While Ohio is still achieving energy savings, the state’s rank will likely fall in the coming years because of the legislation, he said.

October 2, 2019

CAISO Goes 2 for 3 on EIM Hydro Rule Changes

By Robert Mullin

CAISO on Monday scored two out of three as FERC rejected one of the ISO’s proposed Tariff revisions to address concerns that the Western Energy Imbalance Market’s rules constrain the operations of hydroelectric producers and undercut the value of their resources (ER19-2347).

Canada-based Powerex called for the changes shortly after joining the EIM in spring 2018. The company, which markets surplus hydro output produced by government-owned BC Hydro, complained about the frequency with which transmission constraints at the U.S.-Canada border were triggering CAISO’s local market power mitigation (LMPM) process in the EIM, which mandates use of default energy bids (DEBs) to settle transactions. (See Troubled Waters for Powerex in EIM.)

Powerex found that LMPM repeatedly kicked in just as its traders were seeking to buy up energy during periods of low prices. As the company filled inbound transmission with purchases, the mitigation process detected constraints in an area not actually requiring additional power — forcing the company to sell into already flush markets.

The company complained that the inflexibility of the formulas underpinning the DEBs often left its EIM operations out of the money, prompting it to avoid trading in the market altogether.

The hydro-heavy Bonneville Power Administration, which recently signed an implementation agreement to join the EIM, also called for changes. (See Bonneville Power Signs Agreement with EIM.)

CAISO hydro — Pacific Northwest hydroelectric producers sought changes to Western EIM rules that they said undercut the value of their resources. | © *RTO Insider*

CAISO’s Board of Governors responded to the hydro producers’ concerns in March by unanimously approving a set of EIM revisions, including a proposal to create a specially targeted “hydro DEB” that the ISO said “better estimates these resources’ actual costs, which typically consist of opportunity costs reflecting their limited water availability.” (See CAISO Board OKs Market Power Mitigation Remedy.)

The hydro DEB represents the minimum payment a hydro resource would receive under EIM dispatch. The change stipulates the DEB will be calculated at the maximum of one of three components:

Long-term/geographic: representing the opportunity costs for the potential of a resource to sell output in the future, including in different bilateral markets.
Short-term: represents opportunity costs created by short-term water use limitations.
Gas floor: representing the cost of replacement energy in the EIM if the resource exceeds its short-term limitations. It would be calculated based on the average gas turbine heat rate multiplied by the gas price applicable to the relevant region.

The long-term and gas floor components would also include a 10% adder to account for variation between published indices and the prices of actual bilateral transactions, while the short-term component would include a 40% adder to prevent it from being dispatched too frequently on a particular day.

CAISO’s changes also include a provision that alters the timing of LMPM so that the triggering of mitigation during a 15-minute interval will no longer apply to every five-minute period within that 15-minute span; it also will not apply to all subsequent intervals within the same hour. In proposing the change, the ISO expressed concern that existing rules can force EIM resources to sell energy out of their balancing authority areas at mitigated prices even during intervals when no market power has been detected.

A Question of Discretion

In its ruling Monday, FERC approved both the hydro DEB and mitigation timing changes. But the commission rejected CAISO’s proposal to implement a mechanism that would have allowed EIM entities to limit net exports from their BAAs under certain conditions.

In its filing, CAISO explained how an EIM entity must pass a resource sufficiency test at the beginning of each market interval in order for the market to dispatch energy in and out the entity’s BAA during that interval. The test ensures the entity has scheduled sufficient resources and enough flexible ramping capacity to meet its own demand for the interval. There is no requirement for resources within the BAA to offer energy beyond that amount.

“Despite this, the existing market power mitigation process can mitigate a resource’s bids when multiple balancing authority areas are import-constrained, and a resource can be dispatched for additional exports at mitigated bid prices for greater quantities of energy than were required to be offered. This can discourage offering energy and transmission to the EIM,” CAISO noted.

To address the issue, the ISO proposed to introduce a “net export limit” feature that would allow EIM entities to limit the additional dispatch of resources when resources’ bids are reduced because of their BAAs becoming subject to bid mitigation.

As FERC explained in its order, “the optional feature would allow EIM entities to limit net transfers out of the mitigated BAA to the greater of: (1) the pre-mitigation transfer quantity, or (2) the base transfer quantity, plus, for both (1) and (2), the sum of the flexible ramping up awards in the market power mitigation run in excess of the BAA’s flexible ramping-up requirement.”

CAISO intended to enforce the rule in both the 15-minute and real-time markets to ensure that every interval limit was determined separately.

“Each EIM entity would have the option to activate this rule so that the EIM transfer limitations are enforced after mitigation,” CAISO explained.

In rejecting the provision, FERC ruled that it was “inconsistent” with the EIM’s market power mitigation framework and “not an appropriately calibrated solution to the concerns CAISO identifies.”

“In particular, CAISO’s proposal could weaken CAISO’s market power mitigation process by allowing EIM entities to withhold generation through the submission of high supply bids and restricting EIM transfers out of their BAAs,” the commission wrote. “Under CAISO’s proposal, those bids would be mitigated when the potential to exercise market power was detected, but it is the unmitigated bids that would determine the dispatch of resources to serve load outside of the EIM entities’ BAAs. As a result, CAISO’s proposal would effectively allow market participants in the EIM to raise prices above competitive levels at the discretion of the EIM entity, resulting in potentially unjust and unreasonable rates.”

The commission also dismissed CAISO’s argument that the provision was acceptable because the EIM is a “voluntary” market, saying that the Federal Power Act requires FERC to ensure just and reasonable rates in all markets it oversees.

“Resources in the EIM do not have a must-offer obligation in the same way that many resources in CAISO do, but this distinction is not a compelling basis for weakening the protections against anticompetitive behavior in the EIM. Even if resources are not under a contractual or legal obligation to offer supply into a market, allowing the unmitigated exercise of market power by those resources may result in unjust and unreasonable rates,” FERC said.

Pointing out that the proposed change could apply to any resource type, the commission additionally rejected CAISO’s contention that the option was fashioned to address the “unique situation” of hydro resources with storage capability that are dispatched at DEBs that don’t reflect their true opportunity costs.

“Under this proposal, EIM entities could decide whether the net export limit constraint applies to generation within their BAA and then receive congestion revenue as a result of the application of this constraint,” FERC said. “We find that this discretion could potentially undermine CAISO’s independent operation of the EIM because it would allow EIM entities, which are also participants in the EIM, discretion over what constraints are applied to them.”

October 2, 2019

Entergy Control Center Ownership Changes OK’d

By Tom Kleckner

FERC on Monday approved an Entergy request to transfer ownership interests in two transmission control centers from Entergy Services to the company’s operating companies (EC19-18).

The commission found that the transaction would not adversely affect horizontal or vertical competition, noting that the control centers — in Jackson, Miss., and Little Rock, Ark. — have been and will continue to be operated under MISO’s control. FERC also determined that the transaction would not have an adverse effect on rates, as transferring the control center’s ownership will increase administrative efficiency and rate transparency.

The ownership interests will be allocated to Entergy’s operating companies in Arkansas, Louisiana, Mississippi, New Orleans and Texas based on each company’s 2017 coincident peak load. FERC established the peak-load allocation factors in a separate docket (ER19-211).

The commission also granted in part a complaint under Federal Power Act Section 206 by the Louisiana Public Service Commission, one of five regulatory bodies to intervene in the proceeding. The PSC alleged that the Entergy operating companies’ current accounting and rate treatment of the control centers’ costs characterize them as transmission facilities, and that all of their costs should be included in the companies’ MISO formula rates (EL18-201).

FERC denied Entergy’s request to dismiss the PSC’s complaint, saying the Uniform System of Accounts for public utilities requires that “transactions with associated companies … be recorded in the appropriate accounts for transactions of the same nature.”

“Affiliate transactions that are in the nature of transmission expenses must be recorded by the public utility in transmission expense accounts,” the commission wrote. Based upon the requirement, it disagreed with Entergy’s contention that its operating companies “comply with the commission’s accounting rules.”

The commission ordered the operating companies to make a compliance filing within 30 days showing that they have made the required accounting changes and formula rate recalculations. They also must explain how the recalculations will be reflected in the annual formula rate true-up.

The control centers went into service in 2016 and 2017. They replaced five transmission operations centers and a single system operations center previously owned by the operating companies and operated by Entergy Services.

October 2, 2019February 19, 2025

Dems, Enviros Upset Over Solo FERC Nomination

President Trump’s plan to fill the Republican seat on FERC while leaving a Democratic seat vacant isn’t playing well with Democrats and environmental groups.

Trump announced late Monday his intent to nominate FERC General Counsel James Danly to fill the Republican seat opened by the death in January of Kevin McIntyre. Danly’s confirmation would give the Republicans a 3-1 majority, leaving Democrat Richard Glick alone with Chairman Neil Chatterjee and his fellow Republican, Bernard McNamee. (See FERC General Counsel Tapped for Commission.)

“I am disappointed that the president has only announced his intention to nominate a Republican commissioner,” Sen. Joe Manchin (D-W.Va.), ranking member of the Senate Energy and Natural Resources Committee, said in a statement. “FERC has a strong history of operating in a bipartisan fashion, and failing to honor the tradition of a bipartisan pairing sets a dangerous precedent moving forward. I remain hopeful the administration will quickly nominate a Democratic commissioner so we can consider both nominations together and restore a fully functioning FERC.”

Manchin and Senate Minority Leader Chuck Schumer (D-N.Y.) are reportedly backing attorney Allison Clements for the Democratic seat formerly occupied by Cheryl LaFleur. Clements, director of the Clean Energy Markets program at the Energy Foundation, formerly helped direct the Sustainable FERC Project for the Natural Resources Defense Council.

E&E News reported last month that Schumer was threatening to block ENR Committee bills if the Republicans push a GOP nominee without a Democratic pairing.

Sen. Lisa Murkowski (R-Alaska), chair of the committee, told Politico recently that she would not let the lack of a Democratic nominee keep her from holding a confirmation hearing for a Republican.

She issued a brief statement Tuesday acknowledging Trump’s announcement but noting that the committee had not yet received the formal nomination and “associated paperwork” needed before scheduling a confirmation hearing.

“I welcome the president’s decision to nominate a Republican commissioner and to fill a critical seat that has now been vacant for nine full months,” she said.

Environmental groups reacted with indignation over Trump’s announcement.

“Donald Trump’s decision — and Sen. Murkowski’s acquiescence — to exclude a Democratic nominee from his announcement of the Republican counterpart is a breach of precedent and another swipe at FERC’s historically independent mission,” said Mary Anne Hitt, senior director of Sierra Club’s Beyond Coal campaign. “We strongly urge Sen. Murkowski to demand nominees be paired and considered concurrently, and that the administration quickly put forward Mr. Danly’s Democratic counterpart. Not doing so will risk further denigrating this important commission.”

Unqualified?

Sam Gomberg, senior energy analyst for the Union of Concerned Scientists, called Trump’s decision a “marked departure from decades of precedent” and called Danly “woefully unqualified for the job.”

Danly earned his J.D. at Vanderbilt University Law School in 2013 and worked in the energy regulation and litigation group at Skadden, Arps, Slate, Meagher & Flom before being appointed general counsel in September 2017.

“Prior to his appointment to general counsel at FERC, he had a brief stint as an associate energy attorney. I simply don’t see how the American public can have any confidence in his ability to understand the complex issues facing the energy sector right now and to make forward-looking, well-informed decisions on the issues awaiting the commission,” Gomberg said. “His inexperience absolutely increases the risk of a commission unable to defend consumers from biased and politically motivated attacks on our regulatory structure.”

Chelsea Eakin, senior manager for energy transition for climate change activists Climate Nexus, said the departure of LaFleur, who served for nine years, left the commission with a lack of institutional experience. “Combined, the three current commissioners have served for less than half the time LaFleur did and only under President Trump,” she said. “Danly’s confirmation would stack the commission, tasked with making energy decisions that have significant impacts on U.S. emissions, with like-minded Trump appointees in advance of a busy fall agenda.”

John Moore, director of the Sustainable FERC Project, said the Senate should require Danly to answer questions about his “humble regulator” philosophy.

“Before they vote on his nomination, senators must ask him what that means. Would Danly defer to the authority of states to set their own clean-energy policies? Would he continue FERC’s flawed climate review of pipelines that he defended in court?” Moore asked. “Critically, the nomination of only one commissioner when there are two vacancies reflects a further erosion of longstanding norms and undercuts the independence and bipartisan decision making at FERC.”

Nominating Rules

ClearView Energy Partners noted Tuesday that the changes to Senate nomination rules during the 115th Congress reduced the minority’s party ability to stop or slow presidential nominations.

“Although it has been customary to move bipartisan pairs of nominees for independent commissions such as FERC when two vacancies exist, we’d argue that practice had been a function of political necessity given the prior ability of either party to filibuster a nominee,” they said. “Assuming Danly’s paperwork has been or is expeditiously forwarded to the Senate Energy Committee for consideration, we think it is possible that his nomination could move through committee and to the Senate floor by the end of October. Senate consideration can only begin, however, when the White House literally forwards a nominee’s paperwork, and this part of the process has not always happened quickly.”

With only three members, recusals by McNamee or Glick have left the commission without a quorum recently, including a recent vote on FCA 13 Results Stand Without FERC Quorum.)

Glick also is prevented from voting on revisions to PJM’s capacity market until December. (See PJM Suspends Auction Deadlines Pending FERC Action.)

If Danly’s appointment allowed FERC to act on the PJM docket in November, the delayed 2019 auction could be held in mid-2020, before the 2020 auction, ClearView said.

October 2, 2019

FERC Denies Rehearing over RTO Adders

FERC on Monday again upheld the RTO incentives it previously approved for Southern California Edison and Pacific Gas and Electric, rejecting rehearing requests by California regulators.

Commissioner Richard Glick, who had dissented on the 50-basis-point adder to SCE’s return on equity in December 2017, joined with the majority this time around. (See FERC Sets Hearing on SCE Tx Rates; Glick Dissents.)

FERC RTO adders — FERC upheld the RTO incentives it previously approved for Southern California Edison and Pacific Gas & Electric, rejecting rehearing requests by California regulators. | © *RTO Insider*

The commission has repeatedly approved the adder for the two utilities’ participation in CAISO since creating the incentives in Order 659 in 2007.

The California Public Utilities Commission challenged the adders, arguing that the state’s three big investor-owned utilities — PG&E, SCE and San Diego Gas & Electric — were required by state law to participate in CAISO.

In 2018, the 9th U.S. Circuit Court of Appeals remanded the issue and directed FERC to conduct fact finding on whether PG&E could unilaterally leave CAISO. The commission responded with an order in July, saying that the utilities could leave CAISO without CPUC approval and thus were entitled to the incentive. (See PG&E Deserves $30M ISO Adder, FERC Says.)

In Monday’s orders (ER17-2154-001, ER18-169-001, EL18-44-001), FERC reiterated its conclusion, citing a section of the California Code that states that the IOUs “should commit control of their transmission facilities to the independent system operator.”

“The language of these statutory provisions does not mandate participation in CAISO,” FERC said. “Rather … these provisions speak in terms of encouragement and facilitation of participation.”

Glick said that although he dissented from the 2017 SCE order, “I believe that the commission has now adequately addressed the arguments against” the RTO adder.

– Rich Heidorn Jr.

October 2, 2019

Senate ENR Seeks $250M for Utility Cyber Spending

By Rich Heidorn Jr.

The leaders of the Senate Energy and Natural Resources Committee last week announced bipartisan legislation to provide $250 million in funding for transmission owners’ cybersecurity investments as independent power producers said they may seek to recover their compliance costs through RTO capacity markets.

The Protecting Resources on the Electric grid with Cybersecurity Technology (PROTECT) Act, would direct FERC to initiate a rulemaking on rate incentives, and the Department of Energy to offer grants and technical assistance, for investments in “advanced cybersecurity technology.” The DOE program would be for electric cooperatives, municipal utilities and others not regulated by FERC.

Announced on Thursday, the legislation would provide $50 million annually for fiscal years 2020-2024.

Committee Chair Lisa Murkowski (R-Alaska) introduced the bill with ranking member Sen. Joe Manchin (D-W.Va.) and Sens. James Risch (R-Idaho), Maria Cantwell (D-Wash.) and Angus King (I-Maine).

Prospects for the legislation were clouded Monday by President Trump’s announcement that he will nominate FERC General Counsel James Danly to fill an open Republican spot on the commission without also filling the open Democratic seat. E&E News reported last month that Senate Minority Leader Chuck Schumer (D-N.Y.) was threatening to block ENR Committee bills from reaching the floor if the Republicans push a GOP nominee without a Democratic pairing.

The bill, which would amend the Federal Power Act, defines “advanced cybersecurity technology” as “any technology, operational capability or service, including computer hardware, software or a related asset, that enhances the security posture of public utilities through improvements in the ability to protect against, detect, respond to or recover from a cybersecurity threat.”

FERC would be required to initiate a study within six months after the bill’s enactment “to identify incentive-based, including performance-based, rate treatments” to encourage cybersecurity investments and participation in threat information-sharing programs. FERC would be required to consult with DOE, NERC, the Electricity Subsector Coordinating Council and the National Association of Regulatory Utility Commissioners on the study.

The incentives would be available for investments that reduce cyber risks to “defense critical electric infrastructure” and other FERC-jurisdictional facilities “critical to public safety, national defense or homeland security.” Also eligible would be facilities of small- or medium-sized public utilities with limited cybersecurity resources.

Utilities would seek incentives through a “single issue” filing under FPA Section 205 that would be “without regard to changes in receipts or other costs of the public utility.”

DOE would issue grants and technical assistance on a competitive basis, giving priority to companies with limited cybersecurity resources or that own defense critical infrastructure or other assets “critical” to the reliability of the bulk power system.

“The consequences of a successful cyber-incursion would be widespread and potentially devastating,” Murkowski said in a statement. “We know the threat of cyberattacks by our foreign adversaries and other sophisticated entities is real and growing.”

EPSA Report

On Monday, meanwhile, the Electric Power Supply Association (EPSA), which represents independent power producers and marketers, issued a report saying that competitive generators may need to seek additional revenue through RTO operations and maintenance (O&M) charges if cybersecurity rules on them are tightened.

EPSA said regulators should give generation owners “flexibility … to prioritize and address critical security matters.”

“Factors including company size, extent of asset ownership, transmission configuration, physical location and design of facilities, presence in organized wholesale markets, regional resource and system constraints, and prior patterns of theft, vandalism, and other security-related activities all influence analyses and decisions regarding critical asset identification and risk threat assessments by individual companies,” EPSA said. “Should the government opt to vastly ramp up or change cyber and physical security requirements, additional cost recovery avenues or mechanisms may merit consideration for companies that operate in market-based rate regimes.”

EPSA said the costs of complying with additional security requirements should be recovered in a “regional or systemwide basis.”

“As some of the cyber and physical security costs clearly fall into the O&M bucket, the capacity markets are where these costs should be appropriately priced and ultimately recovered. By reflecting these costs into net [cost of new entry] calculations, ISOs/RTOs will ensure that resources can be compensated through the capacity markets for their costs of doing business, including necessary cyber and physical security investments.”

The report also complained that EPSA members sometimes do not learn of security incidents for 18 to 24 months afterward, “which makes preparing for and girding against these threats more difficult or not timely as the incident/threat may have already run its course or caused significant damage by the time they are briefed.

“It is important that companies have access to the critical information needed to ensure that their systems and awareness are up to date,” EPSA continued. “An important improvement would be to ensure that such information is not overly restricted as classified unless warranted, and that there are numerous persons at a company with the necessary security clearance to receive it. The security of the system is far too important to hinge on the availability of one or two people at a company with the necessary clearance to receive timely information.”

“Timely declassification of actionable information is important to grid reliability and security,” NERC spokeswoman Kimberly Mielcarek said. “The quicker the Electricity Information Sharing and Analysis Center and industry receive this information, the better we are able to safeguard the grid and mitigate risk.”

Concern Rising

Concern has risen since the revelations of Russian hackers’ attacks on Ukraine’s electric grid in 2015 and 2016.

In January, the U.S. Intelligence Community’s 2019 Worldwide Threat Assessment reported that Russia has the ability to execute cyberattacks in the U.S. that could disrupt “an electrical distribution network for at least a few hours.”

The report also said that “China has the ability to launch cyberattacks that cause localized, temporary disruptive effects on critical infrastructure — such as disruption of a natural gas pipeline for days to weeks.”

Sen. King has called for more urgency in addressing the threat, saying the federal government should develop an “offensive response” to attacks on the grid and other critical infrastructure. (See “Sen. King Calls for ‘Offensive’ on Cyberthreats,” Overheard at NECPUC 71st Annual Symposium.)

At a FERC technical conference in May, the idea of incentivizing investments to improve resilience received mixed reviews. ITC Holdings said the commission should ensure cost recovery for TOs that go beyond NERC standards “consistent with Order No. 679,” which established incentives to compensate for the challenges faced by specific transmission projects, for forming a transmission-only company and for joining an RTO.

But Alliant Energy rejected the idea of a “resilience incentive,” saying it was unnecessary and would provide a windfall to TOs. “Transmission owners currently do not have difficulty securing financing for transmission projects,” Alliant said. (See Mixed Reaction for ‘Resilience Incentives’.)

In July, NARUC released tools to help regulatory commissions gauge the effectiveness of utilities’ cybersecurity preparedness efforts and the prudence of related expenditures. (See NARUC Offers Tools for Measuring Cybersecurity.)