Page 1140 – RTO Insider

February 20, 2020

PJM May Compress BRA Schedule over MOPR

By Rich Heidorn Jr.

PJM began to sketch out how it will respond to FERC’s order expanding the minimum offer price rule (MOPR) Wednesday, suggesting that it may compress the schedule for the delayed 2022/23 Base Residual Auction and subsequent auctions.

At a special meeting Wednesday morning of the Market Implementation Committee, PJM also said it was considering eliminating two of three Incremental Auctions.

PJM will develop a schedule “that meets everyone’s needs to the best of our abilities,” said Adam Keech, vice president of market services, who added that the schedule will ultimately depend on how quickly FERC rules on the RTO’s compliance with its Dec. 19 order. PJM has said it will not schedule a capacity auction until after FERC rules on its compliance filing due March 18.

On Tuesday, FERC issued a tolling order giving it more time to respond to the requests filed last month for rehearing and clarification of its December order (EL16-49-002 , EL18-178-002). (See PJM MOPR Rehearing Requests Pour into FERC.)

Keech said the RTO could compress the normal nine-month schedule into six months by shifting three deadlines that normally occur in months nine through six: nominations for winter capacity interconnection rights (CIRs); submission of seller peak-shaving adjustment plans; and preliminary must-offer exemptions for deactivations.

PJM BRA Schedule — Typical PJM capacity auction schedule | *PJM*

Keech said leaving the schedule as is could mean those deadlines would come for a given delivery year before PJM had results of the previous auction.

Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), said his members need time to evaluate FERC’s compliance ruling to see if they need to make changes in state policy. OPSI sent the Board of Managers a letter last week asking for at least 12 months after FERC’s compliance order before the next BRA but to cap the schedule so the auction is held no later than May 31, 2021.

“That’s crazy,” Tom Hoatson of LS Power said of such a delay. “There’s business decisions, there’s investment decisions currently on hold. … I think you could run an auction as early as this fall for 2022/23.”

Richard Seide of Apex Clean Energy asked how PJM would respond if Maryland pulls out of the capacity market and adopts a fixed resource requirement (FRR).

But Marji Philips of LS Power called it a “gross exaggeration to say the world has changed.”

“I think it’s time we stop talking about a house on fire. It’s not on fire. … At least for the upcoming auction, there isn’t a lot that has changed.”

“All these ‘what ifs’ are not compelling,” said Bob O’Connell of Panda Power Funds. “PJM needs to set a schedule that includes all preliminary activity. We can always find reasons to push it off.”

Carl Johnson of the PJM Public Power Coalition asked PJM and the Independent Market Monitor whether they expected to have to review more units going through the unit-specific exemption process under the new rules.

“I expect it will be more. How much more, I don’t know,” Keech said, adding that it will depend on the values set for the net cost of new entry (CONE) and avoidable-cost rate (ACR).

“It will be more — probably significantly more,” Monitor Joe Bowring said. But he said the Monitor is trying to streamline its review process. “We don’t want to be the thing that slows us down,” he said. “We’re happy to move as quickly as people need us to.”

Exelon’s Jason Barker said shortening the schedule from nine to six months “seems reasonable” but that it would be disruptive to have overlapping auctions because it could put unit owners in a position of having to make retirement decisions for a subsequent delivery year without knowing if it cleared in a prior delivery year.

“You can put all the caveats in the world around that. It has real-world implications,” he said, noting that a plant could see an exodus of its staff after announcing its retirement, even if it is later rescinded.

Incremental Auctions

Keech said PJM is discussing canceling some first and second Incremental Auctions, noting that the postponed BRA for delivery year 2022/23 will likely be after the September date scheduled for the first IA for that period.

He said the RTO may recommend canceling such IAs any time the BRA is later “because you’ve always got the next [IA] coming up.”

If the RTO were to try to reshuffle the IAs, he said, “the logistics around the auction schedule gets extremely complicated.” Such a change would require FERC approval.

IMM to Estimate Cost Impact

In his own presentation on MOPR floor prices, Bowring presented a template for unit-specific exemption requests and an analysis of net ACR costs for nuclear plants.

Barker challenged Bowring’s estimates, saying they fail to account for the plants’ market and operating risks, which should increase prices by $7/MW-day to $18/MW-day. “Risk should be accounted for. It’s not accounted for in these numbers,” he said.

Other speakers questioned using a 20-year asset life for determining the costs of solar generation, saying it is too short.

“We’re not saying it has to be 20 years; that’s what the order is now,” Bowring said. “We think it serves everyone’s interests to have that clarified.”

Bowring also said the Monitor will be publishing “fairly soon” an analysis that will show that the expanded MOPR will not increase capacity clearing prices — contrary to others’ predictions of large increases. In his dissent on the order, Commissioner Richard Glick offered a “back of the envelope” estimate that capacity costs will increase by $2.4 billion annually. (See FERC Extends PJM MOPR to State Subsidies.)

“We’ll point out why that’s not accurate,” Bowring said of Glick’s estimate. But he said the Monitor will not forecast prices for individual locational deliverability areas because that could reveal confidential information and influence bidding behavior. “We don’t want to get out ahead of the market,” he said.

‘Death Penalty’

Seide challenged PJM for changing its interpretation of what he called the “death penalty” for resources that claim the competitive exemption but later accept a state subsidy.

Paragraph 162 of the order says an existing resource that claims the competitive exemption for a capacity delivery year, but later accepts a state subsidy for any part of that delivery year, will be denied capacity market revenues for any part of that year.

The commission said a new resource that claims the competitive exemption in its first year and later accepts a subsidy “may not participate in the capacity market from that point forward for a period of years equal to the applicable asset life that PJM used to set the default offer floor in the auction that the new asset first cleared.”

“Absent this change, PJM’s proposed language would allow gaming and incent the creation of subsidy programs timed to avoid the qualification window,” the commission said.

MIC Chair Lisa Morelli acknowledged that PJM had considered a narrower interpretation of the ban that would bar new resources for just the delivery year in question. But she said the RTO now agrees with Bowring that FERC intended such a circumstance to result in a lifetime ban.

“If FERC sees that [in PJM’s compliance order] and says that was not what the intent was, then they can correct us,” Morelli said.

“You’re accepting the death penalty,” Seide said.

“We prefer asset life ban,” Morelli responded, prompting laughter.

In their request for rehearing, trade groups representing wind and solar generators said the commission’s proposed rule is “unduly punitive and not proportional to the alleged harm caused.”

Additional MOPR Discussions

In a response to questions from stakeholders, Morelli said PJM won’t publish an “exhaustive list” of what it considers subsidies under the FERC order but will list those on which it agrees with the Monitor in the interest of transparency.

Morelli also released an updated schedule of MOPR discussions, including another special MIC session from 9 a.m. to 12 p.m. on Feb. 28. The MOPR will also be on the agenda for the MIC’s next regular meeting March 11. The Demand Response Subcommittee, which discussed the impact of the expanded MOPR on demand response and energy efficiency Wednesday afternoon, will resume its talks from 9 to 12 on March 12.

February 20, 2020

MISO Advisory Committee OKs 11th Sector

By Amanda Durish Cook

Following a close vote Wednesday, MISO’s Advisory Committee will recommend the RTO create a new sector for hard-to-define members.

The 12-9 vote means the Advisory Committee will advise the Board of Directors that a new Affiliate Members sector is needed so environmental groups in the current Environmental and Other Stakeholder Groups sector can have a singular voice.

The AC will suggest that the new sector not be allowed a vote in either it or the Planning Advisory Committee but have one designated seat for AC meetings and be allowed to offer opinions during the committee’s quarterly hot topic discussions.

The Affiliate Members sector would serve as a home for any MISO member that isn’t participating in another sector. Prospective MISO members must declare a sector affiliation before they can join the RTO.

The AC began debating the merits of an 11th stakeholder sector last year when Lignite Energy Council (LEC), a North Dakota coal lobbying group, approached MISO about membership. Not fitting neatly into any of MISO’s existing 10 sectors, it looked like it would be relegated to the “other” in the Environmental/Other sector. Some AC members said it wasn’t fitting that a sector would contain entities with diametrically opposed views. (See Feb. Vote Planned on 11th MISO Sector.)

MISO’s Power Marketers, Transmission-Dependent Utilities, Transmission Developers and — surprisingly — the Environmental/Other sector opposed the move. Instead, they supported an option that would maintain the Environmental sector’s “other” contingent and prescribe a six-month trial including LEC as a new member. The End-Use Customers sector abstained.

Speaking during the AC’s conference call Wednesday, MISO Deputy General Counsel Timothy Caister said he anticipates the board will now want to hold discussions with the committee over its reasoning behind the decision and its vision for the new sector.

“We stand ready to help support any questions the board or the Advisory Committee might have,” Caister said of MISO’s role.

If approved, the move will require MISO to file changes to its Transmission Owners’ Agreement with FERC.

So far, the proposed Affiliate Members sector seems destined for a fossil-fuel focus.

North Dakota Public Service Commissioner Julie Fedorchak said LEC has penned a nonpublic letter to MISO indicating its support to join the proposed sector. Fedorchak also said the group indicated that it has drummed up interest among other entities interested in joining, including coal and iron mining organizations, coal trade organization America’s Power (formerly known as the American Coalition for Clean Coal Electricity) and various chambers of commerce. As a rule, MISO does not confirm what entities approach it about membership, only revealing new members when its board votes on admitting them.

“We look forward to working with the Lignite Energy Council and others as they join MISO,” AC Chair Audrey Penner said.

America’s Power CEO Michelle Bloodworth said an 11th sector would ensure that “everybody with interest and requisite ability has a seat on the table.”

Bloodworth also asked that the AC revisit the no-vote stipulation in the future as the sector gains more members.

“As the energy industry continues to evolve, key players like the Lignite Energy Council, America’s Power and others who are involved in coal-generated electricity need to remain engaged in MISO’s market discussions,” Bloodworth said in a statement urging the board to support the new sector.

Meanwhile, the AC is planning on holding another panel-style discussion featuring industry experts in lieu of its usual hot topic discussion during next month’s MISO Board Week in New Orleans. The panel will focus on how RTOs deal with resource transition and likely feature one executive apiece from NYISO, CAISO and ERCOT.

February 19, 2020

PG&E Reports $3.6 Billion Q4 Loss

By Hudson Sangree

Pacific Gas and Electric reported multibillion-dollar losses in its quarterly and annual reports Tuesday but said in a separate five-year forecast that it expects sustainable financial performance after it emerges from Chapter 11 reorganization.

“Our focus now is on working with all key stakeholders, including elected officials and state regulators, to position PG&E for emergence as a financially stable company with a renewed and rigorous focus on safe operations and customer service,” CEO Bill Johnson said in a statement.

The company said it would not hold a call with analysts to discuss its Q4 results but included detailed slide present a tio ns in its filings.

In its annual rep o rt, PG&E said it lost $7.7 billion ($14.50/share) in 2019, an increase over the $6.9 billion ( $13.25/share) loss recorded in 2018. Fourth-quarter 2019 losses totaled $3.6 billion ($6.84/share), down from $6.9 billion ($13.24/share) the utility said in its qu a rterly report.

The losses mostly resulted from the 2017 and 2018 wildfires that drove PG&E to seek bankruptcy protection in January 2019. The fourth quarter numbers include a $5 billion pre-tax charge related to its previously announced $13.5 billion settlement with victims of the November 2018 Camp Fire that leveled the town of Paradise, the October 2017 Northern California wine country fires that destroyed part of the city of Santa Rosa and the 2015 Butte fire in the Sierra Nevada foothills.

In its forecast, PG&E said it expects to invest $37 billion to $41 billion in infrastructure improvements during the next five years, resulting in an 8% growth in rate-based revenues. Most of the investments will go to hardening its grid against wildfires. The outlook lists serious risk factors, including future wildfire liabilities, but says PG&E could see nearly $20 billion in annual revenue growth by 2024.

Reducing wildfire risks and focusing on safety will help it avoid future losses, PG&E said. Two-thirds of its revenues come from owning and operating electric, gas and generation infrastructure, the utility said, with the remaining third coming from pass-through costs for procuring commodities.

U.S. Bankruptcy Judge Dennis Montali and the California Public Utilities Commission must approve PG&E’s bankruptcy plan by June 30 for the utility to be able to participate in a $21 billion state fund to insure utilities against future wildfires. The fund and its participation criteria were included in last year’s Assembly Bill 1054.

Access to the insurance fund is regarded as vital to the company’s future because California holds utilities liable for fires ignited by their equipment regardless of negligence.

“Wildfire settlements, regulatory resolutions, the enactment of AB 1054 and [the] establishment of a multi-year investment and rate roadmap resolve uncertainty and provide stability,” the company said. PG&E has secured $59 billion for reorganization, and an additional $27 billion may be raised through future public offerings.

The company assured the financial sector Tuesday that it’s on track to meet the June 30 deadline because it has reached settlement agreements with fire victims, insurance companies and local governments in deals worth $25.5 billion.

“PG&E has made significant progress in our Chapter 11 cases over the past year,” Johnson said. “We have resolved essentially every consequential issue within the bankruptcy court’s jurisdiction, most notably reaching a [$13.5 billion] settlement with wildfire victims.”

However, many fire victims have begun to question the deal because it allocates nearly $4 billion of the $13.5 billion to reimbursing government entities, including the Federal Emergency Management Agency. (See What Spring Could Bring for PG&E.)

Gov. Gavin Newsom, too, has challenged the bankruptcy plan, saying PG&E would have so much debt that it wouldn’t have the tens of billions of dollars needed to harden its grid.

The utility said it is continuing to work with the governor’s office to resolve his concerns, but it acknowledged in its SEC filings Tuesday that its “ability to meet the eligibility and other requirements [of AB 1054] may be adversely impacted by the California governor’s review of the proposed plan.”

February 19, 2020

MISO Begins Software Build on Short-term Reserves

By Amanda Durish Cook

MISO has begun developing the software to create a 30-minute reserve product for use in late 2021.

Following FERC approval of the reserves’ Tariff definition late last month, the RTO said it moved the project status from conceptual design to a software build phase that will last less than two years. The project was originally scheduled to remain in the conceptual design phase through the first half of 2020.

MISO hopes to begin discussing the software with stakeholders at Market Subcommittee meetin g s during the second quarter of this year.

The reserves will be furnished by either online or offline resources capable of being deployed within 30 minutes to meet local, sub-regional and market-wide needs.

MISO short term reserves — MISO regions requiring short term reserves are indicated with red arrows. | *MISO*

The RTO expects the new market product will reduce revenue sufficiency guarantee (RSG) make-whole payments, lessen out-of-market commitments, make market prices more transparent and provide pricing signals that incentivize a greater number of fast-start resources that can meet voltage and local reliability requirements more cheaply. Using the reserves, MISO estimates net production cost benefits of $5 million annually and a $1.6 million reduction in RSG make-whole payments paid in MISO South. (See “MISO Preps Tariff for Short-term Reserves,” MISO Market S ubcommittee Briefs: Oct. 10, 2019.)

FERC approved MISO’s plan for implementing the reserve product on Jan. 31 (ER20 –42).

In the order, the commission disagreed with criticisms raised by Entergy and state regulators in MISO South, who said the proposal was vague and was driven chiefly by economics, not reliability. Entergy and MISO South regulators also demanded MISO conduct more analysis to identify which market participants and load pockets would stand to benefit from the reserve product, arguing that MISO South customers could disproportionally foot the bill for the reserves because it will be used to manage flows on the regional dispatch transfer (RDT) limit between MISO Midwest and MISO South.

FERC said MISO’s reliability versus economic impetus was beside the point.

“Whether managing the RDT is a reliability or economic concern is irrelevant since the limit is a binding constraint that needs to be enforced pursuant to MISO’s settlement agreement with SPP,” the commission said.

FERC said MISO’s reserve design “reasonably allocates costs based on load-ratio share in grouped zones where constraints result in the need” for the reserves. MISO doesn’t need to model benefits according to load pocket, the commission said.

“We find that MISO has supported its proposed short-term reserve product as representing an efficient, transparent, market-based solution for managing post-contingency reserve needs,” FERC said.

February 18, 2020

California Bills Target PG&E, IOUs

By Hudson Sangree

SACRAMENTO, Calif. — State lawmakers have drafted a spate of bills since early January aimed at correcting perceived wrongs by Pacific Gas and Electric and other investor-owned utilities, and they still have a few days left to offer more.

Friday marks the deadline for introducing legislative proposals in 2020, the second year of a two-year session in the State Capitol.

Many of this year’s bills address the public safety power shutoffs (PSPS) that blacked out much of Northern and Central California last fall. One measure lays the groundwork for the state to take over PG&E and turn it into a public utility.

Another bill would let the California Public Utilities Commission place a public administrator inside an investor-owned utility for at least six months to oversee operations and make safety decisions.

That bill, A ssembly B ill 1847, “will help all utilities refocus their priorities on safety and increase needed public confidence in essential electrical utility services,” its author, State Assemblyman Marc Levine (D), said upon its introduction. “California’s economy cannot afford to spend another decade in the dark.”

Some lawmakers had speculated this year could see a legislative free-for-all against PG&E, but the reality has been more restrained. About three dozen bills, of the 753 measures introduced so far this year, have focused on the electric sector, with about half of those geared toward reforming the state’s three big IOUs.

PG&E, the largest and most politically unpopular of the three, is in bankruptcy after two years of catastrophic wildfires ignited by its equipment, including the state’s deadliest blaze, the November 2018 Camp Fire.

The utility came under heavy fire for blacking out hundreds of thousands of customers to prevent more fires in October and November. (See California Officials Hammer PG&E Over Power Shutoffs.)

Taking PG&E Public

The most sweeping of the new bills aimed at PG&E is by State Sen. Scott Wiener (D). Senate Bill 917 outlines a structure for the state to buy PG&E and turn it into a huge public utility, with cities allowed to peel off pieces to create municipal utilities. (See What Spring Could Bring for PG&E.)

California Bills — State Sen. Scott Wiener | *California State Senate*

“The legislation will fundamentally and structurally reform PG&E, whose faulty power lines have caused deadly wildfires, killing hundreds, incinerating thousands of homes, and destroying an entire community [the town of Paradise in the Camp Fire],” Wiener said in a statement.

The bill doesn’t mention PG&E by name. Instead, it would allow state officials to acquire by eminent domain the assets of an IOU that has been convicted of a felony in the past 10 years preceding its seizure.

Jurors convicted PG&E of six felonies in 2016 related to the San Bruno gas pipeline explosion six years earlier. The explosion killed eight people, injured 58 others and destroyed dozens of homes in a suburban San Francisco neighborhood.

Wiener’s measure would let local governments join in the eminent domain action to acquire portions of PG&E’s territory. Cities including San Francisco and San Jose have expressed interest in taking over PG&E’s local assets and creating municipal utilities. (See PG&E Ends Bond Bid as SF Makes Wires Offer.)

A newly formed public-benefit corporation, the Northern California Energy Utility District, would oversee the process of running and dividing PG&E. Billions of dollars in bonds could be issued to buy the IOU, and elected utility officials, not the CPUC, would set rates and adopt policies.

In recent months, Gov. Gavin Newsom has repeatedly said the state will take over PG&E if it doesn’t comply with his demands for major changes, but he hasn’t indicated whether or not he backs Wiener’s bill. (See Newsom Budget Reiterates PG&E Takeover Threat.)

Installing a Public Administrator

Levine’s proposal could increase state control of an IOU without a takeover. Under his bill, the CPUC could embed a public administrator inside any IOU it finds isn’t complying with state laws or regulations.

Intentional blackouts are singled out in the measure.

“The public administrator shall have oversight authority over an electrical corporation’s activities that impact public safety, including the electrical corporation’s decision to de-energize all or part of its distribution or transmission system to reduce the risk of wildfire ignition,” the bill says.

The administrator could stay for up to 180 days, or longer if the “commission adopts a decision in a proceeding making further findings supporting the continued need for the public administrator,” the bill says.

Limiting Harm from Power Shutoffs

A handful of bills seek to minimize the impacts of the public safety power shutoffs.

One bill requires utilities to compensate business owners for food spoilage during blackouts. Another, AB 1915, establishes new rules for the payment of damage claims from PSPS events.

Lawmakers have been especially concerned about the safety, during blackouts, of low-income rural residents who have limited mobility or rely on medical devices. SB 862, a measure by Sen. Bill Dodd (D), whose Northern California district has been plagued by wildfires and safety blackouts, would require utilities to provide backup power or financial assistance in such cases.

Dodd also co-authored a bill that would prevent schools from losing attendance-based funding during power shutoffs. And he introduced a measure, SB 947, that would require the CPUC to base utility revenues on meeting safety and reliability goals.

“A performance-based model will discourage the type of reckless behavior responsible for devastating wildfires and power outages, while promoting responsible practices that have been sorely lacking,” Dodd said. “We need to be innovative to force accountability and achieve acceptable performance.”

Meeting Climate Goals

Measures focused on climate change and greenhouse gas emissions also will occupy this year’s legislative proceedings.

A proposal by Republican lawmakers would revise the definition of a renewable energy resource under the state’s renewable portfolio standard program to include large hydroelectric facilities and nuclear power plants.

In prior legislation — notably SB 100 passed in 2018 — California established ambitious goals of eliminating fossil fuels and carbon emissions by midcentury. (See Calif. Gov. Signs Clean Energy Act Before Climate Summit.)

A “green new deal” bill was introduced earlier this year by Assemblyman Rob Bonta (D). The measure lays out broad aims of fighting climate change and income inequality while offering few specific proposals for achieving those goals.

When he introduced AB 1839 in January, Bonta said it would get fleshed out over time, which will likely be true of other bills as well.

After the introduction deadline passes, policy committees — including the Senate Energy, Utilities and Communications Committee and the Assembly Utilities and Energy Committee — will begin weighing and helping to shape the proposals.

That process runs through mid-May. The deadline for bills to be passed by the State Legislature is Aug. 31, and the governor has until Sept. 30 to sign or veto the measures.

February 18, 2020

FERC Approves SPP’s PMU Installations

FERC last week accepted SPP’s proposed Tariff revision requiring the installation of phasor measurement units (PMUs) at new generator interconnections (ER19-2845).

The commission determined the PMUs will “provide data to SPP that it can use to improve system reliability and system model validation, and that may assist with compliance with current or future NERC requirements.”

“We expect that PMUs will also enhance SPP’s phase angle monitoring, voltage stability assessments, wide-area situational awareness and post-grid event analysis,” the commission wrote.

SPP PMU Installations — A phasor measurement unit | *Siemens*

FERC in August 2018 rejected an early version of the proposal over cost concerns raised by renewable energy developers. It directed SPP to clarify how transmission owners would treat PMU installation costs to avoid including them in transmission rates. Otherwise, FERC said, nonaffiliate customers could end up subsidizing installations for generators belonging to TOs or their affiliated interconnection customers. (See “Commission Rejects PMU Proposal over Cost Concerns,” 3rd Time’s a Charm for SPP Resource Adequacy Proposal.)

SPP’s revised filing retains a requirement that PMUs be installed for all resources 50 MW and above and requires that PMU equipment be installed by the TO on its side of the system before a resource’s initial synchronization date. The revision also makes clear that the PMU equipment will become part of the TO’s interconnection facilities and be funded by the interconnection customer.

The commission rejected an argument by EDP Renewables North America and RWE Renewables Americas that PMUs should be considered network upgrades and that their ongoing communications and operations and maintenance costs should be borne by transmission customers. It said SPP’s designation of PMUs as being TO interconnection facilities was reasonable “because the PMUs are equipment owned, controlled or operated by the transmission owner between the point of change of ownership to the point of interconnection.”

The change is effective Nov. 20, 2019.

Revamped Rate Design Approved

The commission also issued a letter order Feb. 6 accepting SPP’s revisions to Schedule 1A of its Tariff that will replace a broad rate schedule with four targeted ones, effective Jan. 1, 2021 (ER20-4 18).

Under the new rate design, four schedules will replace Schedule 1A’s previous rate with the hope of better aligning beneficiaries with payers and including energy transactions.

Planning, scheduling and dispatch costs will be paid by transmission customers; financial administration costs by their users; market-clearing costs by virtual and real-time market participants; and markets facilitation by real-time market participants. Market costs will be recovered through energy charges and planning costs through demand.

A Schedule 1A Task Force provided much of the design work, which was approved by SPP’s Board of Directors and the Markets and Operations Policy Committee in January 2019. (See “Board Approves Modernized Cost-recovery Structure,” SPP Board of Directors/Members Committee Briefs: Jan. 29, 2019.)

— Tom Kleckner

February 18, 2020April 9, 2024

Overheard at GCPA’s Annual MISO South Conference

NEW ORLEANS — The Gulf Coast Power Association’s seventh annual MISO South Regional Conference drew 175 attendees to the Crescent City last week for panel discussions on resource needs, transmission cost allocation and planning and other key initiatives.

MISO CEO John Bear keynoted the event Wednesday, addressing the “significant challenges” the RTO and its members face.

The bottom line? RTOs and ISOs can no longer incrementally move themselves forward.

“We have too much coming too fast,” Bear said.

Attendees listen to a presentation during GCPA’s annual MISO South regional conference. | © RTO Insider

He pointed to a slide that showed coal’s portion of the generation mix falling from 76% in 2005 to 47% in 2018. The same period saw gas grow from 7% to 27% of the generation mix and renewables from very little to 8%. Retirements have been a major factor, with MISO approving 24.3 GW of retirements — 95% of that fossil-fueled — since 2005.

“[Coal-fired] retirements have caused us to step back and look at things,” Bear said. “These big machines have been online for a long time, providing attributes that we took for granted. They were just there. We didn’t know we needed them or where we needed them.”

MISO, like almost everyone else, continues to add more renewable energy. Wind, solar and other renewables account for 75 GW of the 89 GW in MISO’s interconnection queue, Bear said. Solar interconnection requests increased from 34 GW in 2018 to 51 GW last year.

The RTO’s proposed future planning scenarios reflect the expectation that considerably more wind and solar energy will be added. (See related story, MISO Outlines Electrifying Tx Planning Futures.) The three futures range from a scenario where the footprint develops in line with utility announcements and plans, state mandates and goals, to one of sharply increasing demand because of heavy electric vehicle adoption and residential and commercial electrification driven by policies supporting substantial reductions in carbon emissions.

GCPA Executive Director Kim Casey chats with MISO CEO John Bear before his keynote presentation. | © RTO Insider

“If we’re going from where we are today, with what’s been announced, we’re going to have to add twice as much intermittent generation twice as fast. Can we increment our way there?” Bear asked.

Complicating the equation, he said, is that MISO’s most recent stressful system situations did not take place during the summer, but during January and September of 2018 and January 2019. No longer can the RTO use Aug. 1 as the benchmark for determining the need and value for capacity.

“It’s an interesting exercise, but we’re going to have to change that,” Bear said. “How do we accredit this capacity? Is it seasonal? Is it monthly? Our goal is to have those discussions with the stakeholder community over the next few months and move those forward.”

Bear said the questions need to be answered to inform the policy and resource investment decisions being made by member utilities, but the answers must also be flexible as MISO learns more about changing generation fleets and technologies.

“If we sit still, it’s not going to work very well,” he said. “It won’t be a journey where we take one step and look back and say, ‘That was easy.’”

Transmission Needed to Unlock South’s Solar Energy

A panel of MISO’s southern members stressed the importance of solving the north-to-south constraint between the RTO’s legacy footprint and its South region. The constraint has been blamed for energy shortages and hampering the flow of renewable energy.

While not wind-rich, the Gulf Coast is a hotbed of solar power. About 80% of the 13.4 GW of interconnection requests in the region are for solar-powered resources.

“We believe there’ll be an increase in intermittency,” said Cooperative Energy COO Nathan Brown, whose Mississippi co-op runs a 52-MW solar facility that can ramp up to 96% capacity in two hours. “We see resources somewhere will have to respond to this. Fifty-two megawatts is not that big, but with 9,200 MW in the queue, you’re going to have to have operational flexibility to handle those resources.”

“Resource availability [and] resource needs are not a new problem. We’ve dealt with this well before MISO came along,” Cleco Power President Shane Hilton said. “We’re seeing an aging fleet across Louisiana and across MISO in general. We have several older units, 40 to 50 years old, and we’re seeing increased outages. Cleco and others are having to make decisions around retirements.

“Louisiana is not advancing fast with renewable technology, but it’s coming and it’s coming fast,” he continued. “There’s going to be an increased reliance on solar, wind and battery technology in Louisiana. We’re going to have to figure out that right mix of resources, and the market signals to incent those resources to respond. Technology is advancing faster than I’ve seen in my 30 years with Cleco. We have to be thinking about this soon, and we have to be developing plans soon.”

EDP Renewables’ David Mindham, a self-described recovering transmission planning engineer, offered an answer: “Spoiler: Transmission will be part of the solution.

“MISO has a significant footprint with a lot of geographic diversity. The north could really benefit from solar energy, and the south could really benefit from wind energy in the north,” Mindham said. “Transmission has to be part of the consideration. With higher renewable penetrations across the footprint, geographical diversity is going to matter even more. We need proactive transmission build.”

MISO, Stakeholders Chart Path Forward

Scott Wright, MISO’s executive director of market strategy and design, explained how the RTO is leveraging its system design to address the megatrends reshaping the industry’s landscape.

“MISO has to be all about availability, flexibility and visibility,” he said. “The availability of the transmission system and energy resources to get their attributes where they’re needed. Flexibility … not just adapt when we see things change, but let’s anticipate. Let’s look ahead. MISO wants to be able to enable those sorts of things.”

Wright is currently updating MISO’s Forward report, which uses stakeholder input to address what he called the “three Ds” — demarginalization, decentralization and digitalization — that are changing the industry. Forward 2020 is due to be released in March, with a focus on high wind penetration and distributed generation, among other topics.

Gregg Dixon, CEO of demand response consulting firm Voltus, said he fully expects distributed energy resources to play a major role.

“We think the growth of DERs will surprise you. Solar, EVs … five years hence, you’ll see that today’s estimates were too low,” he said. “Whether EVs or data centers, these are massive customers that dwarf the stakeholders in our industry. They’re making billions of dollars’ worth of investments every year. They see issues with the changing environment, with record hurricanes and California wildfires, and they will have a great voice in these arenas. I think they will shock us all.”

Transmission, Costs Pose Sticky Issues

A diverse stakeholder panel debated two key subjects dominating the discussion in MISO: transmission planning and development, and the applicable cost allocation and rate-recovery design.

GridLiance CEO Calvin Crowder set the stage by asking, “Why is consensus on regional transmission so hard?

“You would think the regionality of RTOs and the independence of ISOs would follow along with cost allocation, but it didn’t, because it tends to get messy when you have winners and losers,” he said, responding to his own question. “Because we’ve had disparities in pricing, looking at things in a regional sense and the impact to players is a big deal. A lot of transmission is integrated with generation and retail services, so there are competing interests.”

Charles Long, vice president of transmission planning and strategy for Entergy Services, echoed Crowder’s comments on competing interests.

“It’s really hard because uncertainty is broader than it’s ever been in the industry,” Long said, pointing to “widely divergent” futures. “Still, there are some strong business cases out there for transmission. We’ve built a lot of transmission over the last 15 years, and it’s getting to the point where we have diminishing returns. These are long-term investments. Customers pay for them over a long time. We want those benefits to be robust, and we want robust business cases.”

Former Missouri Public Service Commissioner Daniel Hall, now with the American Wind Energy Association, said MISO’s most recent significant transmission buildout in 2011 has been recognized as a success to ratepayers. Unfortunately, he said, that additional capacity is pretty much spoken for.

“That congestion is preventing cheaper electricity from flowing to certain parts of the footprint, including MISO South,” Hall said. “It’s widely understood that renewable energy is about the cheapest energy around … and most people understand that new transmission needs to be built. Where this consensus breaks down is the extent and timing of this increase in demand for renewable energy. There’s not a consensus on which benefit metrics to use or how to determine which regions benefit from new lines. The MISO footprint has changed. It’s larger and its membership is more diverse than 2011.”

David Carr, special counsel to the Mississippi Public Service Commission, put the cost-allocation challenge into starker terms: “It’s going to be difficult to go into the Mississippi Delta and convince someone their light bill needs to go up so Minnesota or Google can meet their corporate environmental goals.”

Saying he was no “fan of socialism” — “except when you socialize transmission rates” — Crowder said the most efficient model would be a national, FERC-mandated postage stamp rate, where costs are allocated equally across the system, regardless of the geographical region. However, he’s not optimistic.

“Politically, that’s never going to happen, because you would have huge winners and losers,” Crowder said, noting the elimination of arbitrary barriers, such as voltage levels or cost thresholds, as incremental steps that can be taken now.

“The status quo is unacceptable,” Hall said. “Our ratepayers are being harmed by the current situation. Cheaper energy is not flowing and new generation is not interconnecting. It’s a problem that’s not sustainable. We don’t know exactly what the future holds, but we know damn well it will include a lot more demand for renewables.”

February 18, 2020

Report Marks a Decade of Energy Transition

BloombergNEF’s annual Sustainable Energy in America Factbook is a smorgasbord of data that energy policy nerds have hungrily consumed since the company started publishing it eight years ago.

For its 2020 edition, released last week, BNEF combined last year’s data with a look back over the last decade, “10 extraordinary years [in which] the U.S. fundamentally overhauled how it produces, delivers and consumes hydrocarbons, electrons and heat.”

Here’s some of the highlights of the report, which BNEF produced with the Business Council for Sustainable Energy (BCSE).

Energy transition — U.S. electricity generation by fuel type | *BloombergNEF*

Natural Gas & Coal

Domestic natural gas production rose more than 50% during the decade and 8% in 2019, pushing the U.S. from a net importer to a net exporter. The gas distribution pipeline network grew from 2.09 million miles in 2009 to 2.24 million through 2018 (the last year for which there is complete data).

Gas prices dropped to 2016 levels last year, with Henry Hub natural gas trading below $3/MMBtu every month except January.

Power sector demand for natural gas rose 60% as gas-fired generation’s share jumped from 24% to 38% over the decade. Coal’s share declined by almost half, from 45% to 23%. About 12 GW of coal-fired generation shuttered in 2019 and another 14 GW of retirements have been announced for the next three years.

Renewables & Storage

Generation from renewables spiked 77% during the decade, fed by new utility-scale wind and solar projects and rooftop solar. Renewable capacity doubled over the same period, with installed wind tripling to 108 GW and solar increasing 80-fold to 75 GW. The U.S. is second only to China in renewable capacity.

Last year was the second biggest ever for new non-hydro renewable energy capacity, with 20 GW commissioned, most of it wind and solar. Wind generation rose to 302 TWh in 2019 from 273 TWh the year before, surpassing hydro generation, which dropped from 293 TWh to 276 TWh. Renewables powered 18% of electric consumption in 2019.

U.S. electric generating capacity build by fuel type | *BloombergNEF*

“In a potential harbinger, U.S. hydro, wind, solar, biomass, geothermal and waste-to-energy produced more than the country’s fleet of coal-fired power facilities in April 2019,” surpassing coal for the first time, BNEF said.

Corporations — including oil companies looking to reduce extraction-related emissions — signed a record 14 GW of bilateral renewable energy power purchase agreements last year.

In the last two years, projects that pair renewable technologies with large-scale batteries have become economically viable. (See related story, Energy Storage: All Grown Up?)

From 2010 through 2018 (the last year for which complete data are available), investor-owned utilities invested an average of $18.9 billion a year (2018 dollars) in transmission, nearly double their inflation-adjusted spending for the previous decade. Renewable developers, however, say they need far more transmission to move power to load centers from wind- and solar-rich regions.

Efficiency, Economy, Emissions

U.S. energy demand increased little over the decade despite 10 consecutive years of economic growth since 2009. While U.S. gross domestic product rose 25%, total energy use was up only 6.6%.

In 2019, energy productivity — the ratio of GDP growth vs. energy consumption growth — rose 3.3% as GDP grew by 2.3%, while energy consumption declined 1%.

Lower energy costs have contributed to low inflation, with U.S. households now spending less than 4% of their average monthly income on energy spending, down from 5.1% 10 years ago.

Meanwhile, as of 2018, 3.5 million people were working in the energy efficiency, energy storage, renewables, nuclear and natural gas industries.

Greenhouse gas emissions from power plants dropped by nearly 25% for the decade, making the sector the second largest emitter, behind transportation. Less extreme weather contributed to a 2.8% drop in power consumption in 2019. “Lower top-line demand coupled with the general move toward a cleaner power matrix caused power sector-related emissions to crater by a rather incredible 7.8%,” BNEF said.

However, it said climate change is causing higher high and lower low temperatures, increasing air conditioning and heating demand. “If these trends persist, increased energy consumption can make efforts to reduce energy sector emissions more difficult,” it said.

Transportation sector emissions rose 5% during the decade despite the growth in electric vehicles. U.S. consumers now have a choice of 44 pure battery electric models and 35 plug-in hybrid electrics. EV sales totaled 1.4 million for the decade but dropped 11% in 2019 versus 2018. EVs represented only 1.8% of U.S. vehicle sales for the year. (See related story, Spotty EV Growth, TOU Enrollment Challenges States.)

Nine states increased their renewable portfolio standards in 2019, and states such as Washington, Nevada and New Mexico set zero-carbon, energy efficiency and fuel efficiency targets.

– Rich Heidorn Jr.

February 18, 2020

ERCOT Board of Directors Briefs: Feb. 11, 2020

ERCOT CEO Bill Magness last week told the Board of Directors that the grid operator finished 2019 with a net positive variance of $35.4 million, boosting the pool of funds to implement real-time co-optimization (RTC).

Magness said during the board’s Feb. 11 meeting that a preliminary budget review indicated a 13.3% increase in revenues and a 3.4% decrease in expenditures. He credited a $19.2 million increase in interest income and a $6.5 million increase in system administrative fees for much of the positive variance.

Interest income was coming in over budget as a result of higher balances and rates, Magness told the board in April. The unexpected revenue has been set aside to fund an RTC development pool, now at $52.5 million. ERCOT has estimated it will cost at least $40 million to add RTC to the market.

Magness said the administrative fee variance benefited from warmer-than-normal weather from August into October. September provided $2.4 million and August $1.3 million in actual revenue above budget. October and November accounted for $800,000 and $700,000, respectively, in overages.

October “is kind of what you would expect,” Magness said. “September was the really unusual thing.”

ERCOT’s load continues to grow, with a 2% increase in annual energy usage between 2018 and 2019, after a 5% increase between 2017 and 2018. Over the past decade, energy use is up 20.4%, from 319,097 TWh to 384,040 TWh. The decade before, energy use was up 7.7%.

“[Growth] was as substantial as it felt like, and we continue to see growth,” Magness said.

Real-Time Co-optimization Team Finalizes Scope

ERCOT’s Matt Mereness thanked “all y’all” as he secured the board’s approval of the final batch of RTC key principles that will guide the grid operator’s addition of the market tool into its energy market.

RTC procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements. (See “Committee Endorses Final Real-time Co-optimization Principles,” ERCOT Technical Advisory Committee Briefs: Jan. 29, 2020.)

Mereness chaired the Real-Time Co-optimization Task Force, which wrapped up nine months of work by producing a 44-page document that defines the principles, or boundaries, that staff and stakeholders are working toward.

“It’s been painful but focused,” Mereness said of the group’s 16 meetings. “Collaborative, not always perfectly unanimous, but working together to find solutions. One secret that made it work is we had a single forum. All the smart people were in the room working on it.”

Congratulated by board Chair Craven Crowell, Mereness responded, “It takes a village.”

Staff plan to file a set of Nodal Protocol revision requests (NPRRs) implementing RTC in March. The task force will serve as a clearinghouse to address language changes and comments, with a goal of submitting all NPRRs to the Protocol Revision Subcommittee for its consideration in November. If everything stays on schedule, the Technical Advisory Committee and the board will see the final NPRRs in November and December.

According to its schedule, RTC will be added to the market by mid-2024 before a planned update to ERCOT’s Energy Management System.

Helton, Lange Re-elected to TAC Leadership

The board approved staff’s determination that developing systems to enable economic dispatch over DC ties between the grid operator and other systems would be “prohibitively complicated and expensive” and is not “presently feasible.” Staff said existing systems and processes are sufficient enough to manage congestion caused by DC ties.

“A five-minute dispatch would be technically and jurisdictionally a challenge,” Mereness said.

ERCOT had been directed by Texas’ Public Utility Commission to study and determine whether some or all DC ties should be economically dispatched or whether implementing a congestion management plan or special protection scheme would more reliably and cost-effectively manage congestion caused by DC tie flows.

Nick Fehrenbach, city of Dallas | *ERCOT*

The directive was one of 14 related to Pattern Development’s Southern Cross Transmission, a proposed HVDC line in East Texas that would ship more than 2 GW of energy between the Texas grid and Southeastern markets (46304). (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

Nick Fehrenbach, manager of regulatory affairs and utility franchising for the city of Dallas, pointed out the Southern Cross project is a “commercial venture for economic benefits” and raised concerns about the import and export of power outside economic dispatch.

“This troubles me,” Fehrenbach said. “I don’t know the next project of this nature, but this is something we need to resolve in the long run.”

Mereness said that ERCOT has changed its scheduling of DC ties. As their ramp comes in, it is offset by the grid operator’s economic dispatch.

Leadership Re-elected

In other action, the directors re-elected Crowell as chair, former PUC Commissioner Judy Walsh as vice chair and Magness as CEO, and ratified ERCOT’s officers.

The board’s consent agenda, which passed unanimously, included 16 NPRRs, single revisions to the Nodal Operating Guide (NOGRR) and Verifiable Cost Manual (VCMRR) and a system change request (SCR):

NPRR826: creates a new process for determining the mitigated offer cap for reliability-must-run (RMR) resources.
NPRR838: revises the RMR process by removing the requirements for units to submit operations and maintenance estimates and for RMR resources to submit quarterly O&M updates.
NPRR955: defines a limited-impact RAS to accommodate NERC Reliability Standard PRC-012-2.
NPRR963: allows an energy storage resource’s (ESR) components to be considered in aggregate for generation resource energy deployment performance scoring, controllable load resource energy deployment performance scoring and settlement of base point deviation charges.
NPRR964: removes from the RMR process the term “synchronous condenser unit” and its related agreement.
NPRR967: removes the 10-MW limit for limited-duration resources.
NPRR970: clarifies the fuel-dispute process for reliability unit commitment (RUC) make-whole payments.
NPRR971: updates the energy offer curve’s cost cap value.
NPRR974: requires ERCOT to include additional data about the amount of projected capacity available in the short-term system adequacy report.
NPRR977: requires ERCOT to post a report of canceled RUCs to the market information system.
NPRR978: incorporates revisions to address recent changes on the PUC’s resource adequacy reporting rules.
NPRR980: changes how forced outages longer than 180 days are treated in ERCOT’s Capacity, Demand and Reserves report.
NPRR982: clarifies that a deployed block-load transfer will be appropriately compensated.
NPRR985: modifies the time period used to compute the forward adjustment factor components of the total potential exposure calculation and clarifies that the three forward weeks commence on the applicable operating day, rather than following the operating day.
NPRR986: gives ESRs more flexibility in updating real-time energy offer curves and bids.
NPRR988: corrects NPRR929’s intended implementation by clarifying that conditions in its language are necessary for determining whether a point-to-point obligation with links to an option bid is eligible to be awarded.
NOGRR183: aligns the Nodal Operating Guides with NERC’s remedial action scheme reliability standard.
SCR806: adds resource-specific offer information to all individual disclosure reports on ERCOT’s website.
VCMRR026: removes an appendix to align the manual with NPRR970’s proposed protocol language and NPRR617’s revisions.

— Tom Kleckner

February 18, 2020

Energy Storage: All Grown Up?

By Rich Heidorn Jr.

WASHINGTON — Jason Burwen, vice president of policy for the Energy Storage Association, took his audience down memory lane Wednesday, recalling the industry’s growth since he joined the organization in 2015.

At the time, he told an audience of 200 at ESA’s annual Energy Storage Policy Forum, there was only 200 MW of non-hydro storage on the grid, virtually all in front of the meter and less than one hour in duration. The market was almost entirely frequency regulation.

Just five years later, there is more than 1,500 MW of storage online, one-third of it behind the meter, with some batteries capable of injecting energy for up to eight hours. In addition to providing ancillary services, it is also seeking roles as capacity and transmission. It is increasingly being paired with solar and wind generation.

“We are a mature industry,” Burwen said, slowing for emphasis.

It’s not all rosy, however. Burwen decried the Trump administration’s tariffs on storage technology imports.

“We have a global supply chain in the energy storage industry and certainly just as we are getting our legs underneath us, it is [an] incredible setback to have that uncertainty when folks are contracting years down the line,” he said. “So, that’s something that we’re trying to make sure that the administration is aware of — recognizing how much effort is going into promoting resilience and [how] storage can be key part of that.”

Storage remains dwarfed by wind (108 GW) and solar (75 GW) generation in installed capacity. And although ESA formed a political action committee last April, it raised less than $5,000 and disbursed only $2,000 in 2019. The American Wind Energy Association’s PAC disbursed more than $78,000 last year and more than $300,000 in the 2018 cycle. The Solar Energy Industries Association PAC spent almost $179,000 in the 2018 campaigns and more than $63,000 in 2019.

But there’s no doubt storage has gained some clout in D.C. As ESA was having its forum, CEO Kelly Speakes-Backman was testifying before a House Energy and Commerce subcommittee. She spoke in support of HR 4447, which would provide technical assistance to rural electric cooperatives for storage and microgrid projects, and HR 1744, a bipartisan bill that would amend the Public Utility Regulatory Policies Act to require utilities to consider storage in their supply-side resource planning processes.

Burwen said the industry “accelerated dramatically” last year. Congress saw the introduction of more than a dozen bills promoting storage, some calling for an investment tax credit. FERC conditionally approved RTOs’ compliance plans with Order 841, the commission’s 2018 rulemaking requiring the RTOs to allow energy storage resources full access to their markets. (See Storage Plans Clear FERC with Conditions.) New York and California expanded their storage incentives, with Nevada finalizing a storage target and Maine and Virginia recommending them. (Last week, Virginia lawmakers approved a 3,100-MW energy storage target by 2035.)

Battery storage costs have dropped dramatically, along with the cost of solar and wind generation, opening new opportunities.

“In the last two years, projects that pair renewables technologies with large-scale batteries have for the first time become economically viable,” BloombergNEF reported in its 2020 Sustainable Energy in America Factbook, released last week. “In particular, ‘PV-plus-storage’ projects have under-bid natural gas-fired plants to win power-delivery contracts in certain states thanks to a 77% drop in the price of a typical PV module and an 87% decline in battery pack prices.”

ESA says its “vision” is to reach 35 GW of storage by 2025, a 23-fold increase from current levels. “This is undoubtedly ambitious and will require fundamental changes in how the grid is planned and engineered, including a reform of U.S. energy markets and regulations,” ESA said.

It projects that electrifying transportation and buildings will add more than 3,500 TWh of annual demand in addition to current U.S. consumption of 4,200 TWh, with annual additions of storage reaching 7 GW in 2024. Wood Mackenzie Power & Renewables projects a more modest deployment of 4.4 GW in 2024.

To reach its goal, ESA is focusing its policy efforts on three goals: ensuring the ability to interconnect to the grid, which FERC supported with Order 845; including storage in all planning processes and procurements as an alternative to other resources; and winning compensation for the resource’s flexibility and other attributes.

The association has called for updating utility integrated resource planning to consider storage as an option for system capacity. IRPs, Burwen said, will be “the new RPS” (renewable portfolio standard). In the next five years, storage will become a “fully integrated part of” discussions on reaching 100% clean energy targets, Burwen said.

“In some respects, the last five years have been about mainstreaming energy storage as supply. And the next five years, we’re probably talking about mainstreaming energy storage as infrastructure, both in the grid and in the built environment,” he said.

RTOs Discuss Opening Doors for Storage

Panel discussions earlier in Wednesday’s conference included state regulators and officials from CAISO, MISO, PJM, ERCOT and NYISO.

Burwen asked one panel about RTOs’ role in resource adequacy, citing FERC’s controversial Dec. 19 order requiring an expansion of PJM’s minimum offer price rule (MOPR) to cover new state-subsidized resources. State officials have criticized the ruling as an attack on their jurisdiction over resource adequacy; some are considering withdrawing from the capacity market as a result. (See PJM MOPR Rehearing Requests Pour into FERC.)

Michael DeSocio, NYISO’s director of market design, said the issue is the subject of “conversations” in the ISO’s stakeholder processes and proceedings of the New York Public Service Commission.

“What we’re really looking for is a little bit of time. … These are complicated issues,” he said. “The markets have offered a level of transparency that you didn’t have before the markets existed, [which] is really important so you get a fair shake at making a go out of it. … I’d really hate to see that go away. So, we’re working hard to see if we can come up with solutions to those concerns.”

In a second RTO/ISO panel, ERCOT’s Kenneth Ragsdale said that although the Texas grid operator is not under FERC jurisdiction, Order 841 “helped us rationalize why we need to spend more time on storage.”

“We’re looking at how we can integrate [storage] with the system we have. … We’ve looked at allowing bid offer curves to be updated intra-hour instead of once at the hour. … We are trying to find the proper way to represent what this asset can provide to us [for resource adequacy]. We are really trying to get away from, ‘No you can’t interconnect that,’ to ‘Yes.’”

Stacey Crowley, CAISO’s vice president of external and customer affairs, said the ISO and storage providers are in the middle of a “trust-building exercise.”

“The operators are going to need to trust that those resources are there when the resource says they’re going to be there,” she said. “One of our really smart attorneys said, ‘Stacy. This is a marathon. And we are literally just tying our shoes right now.’”

Burwen noted that MISO generated controversy in December when it became the first RTO to file a proposal with FERC for treating storage as transmission.

The RTO’s storage-as-transmission-only assets (SATOA) proposal drew complaints that it would provide transmission owners a monopoly (ER20-588). The RTO said it was an initial step designed to avoid complexities over cost recovery, such as how non-TOs would be compensated for providing transmission services. SATOA resources would be barred from simultaneous participation in MISO’s energy market, at least initially. (See MISO SATOA Proposal Faces Opposition.)

Laura Rauch, MISO’s director of settlements, acknowledged the proposal is “imperfect.”

“If you read our filing, you saw that we acknowledge that this is … only a first step,” she said.

Glick Seeks Tech Conference on Hybrid Resources

In a keynote speech, FERC Commissioner Richard Glick acknowledged his two years on the commission have been “maybe a little more contentious than previous FERCs have been. We’ve had, certainly, quite vivid and interesting debates among the different commissioners and advisers.

“One of the reasons is that the transition to a clean energy future … creates a lot of conflicts,” he continued. “People that were in the business before that see their technologies are maybe on the way out are going to fight very hard. … There are winners and losers. Not everything is a win-win situation.”

“Chairman [Neil] Chatterjee has stated a number of times … he wants to make FERC boring again,” he continued, sparking laughter from the audience. “I have to say, he just hasn’t succeeded quite yet.”

But Glick credited Chatterjee for supporting Order 841 — one of the few times that the chairman voted differently than his fellow Republican, Commissioner Bernard McNamee.

He expressed hope that the commission will return to the issue of aggregated distributed energy resources, which it declined to act on in Order 841. “In my view, we should be ready to go. I don’t think there’s any additional information we need,” he said, noting the commission held a technical conference and received comments on the issue. (See Commenters Divided on DER Aggregation, State, LDC Roles.)

He also expressed confidence that the commission will prevail in a legal challenge over its jurisdiction over storage, noting the Federal Power Act gives it authority over all sales for resale, “even behind the meter.” State regulators, utilities and public power groups asked the D.C. Circuit Court of Appeals in July to overturn FERC’s decision not to allow states to opt out of Order 841. (See States, Public Power Challenge FERC Storage Rule.)

Glick said he wants to learn more about reports that storage providers have been reluctant to enter the energy markets in some regions, saying their involvement will be necessary to accommodate a big increase in intermittent renewables. “Especially if we don’t build as much transmission as we need to build, the only way to deal with this extra intermittency is through storage. A lot more storage.”

He also said FERC should hold a technical conference on hybrid storage. Among the questions the commission needs to answer, he said, is how the addition of storage to an existing solar or wind project affects its position in the interconnection queue and whether it is treated as a dispatchable or intermittent resource. “We need to learn what some of these issues are — what some of the barriers are — for hybrid technologies,” he said.