ST. PAUL, Minn. — Google gained a foothold in the MISO system last week as the RTO’s Board of Directors approved a subsidiary’s membership application.
Google Energy joined MISO’s Eligible End-User Customers sector. The subsidiary was founded nearly a decade ago in a push to power its parent’s operations with 100% renewable energy. It has multiple investments and power purchase agreements with wind farms along the western border of MISO’s footprint, enough by 2017 to match its annual electricity consumption.
“Although our 100% renewable milestone signifies that we buy enough renewable energy over the course of a year to match our annual electricity consumption, it does not mean that our facilities are matched with renewable energy in every hour of every day,” the company says. Its ultimate goal “is to source enough carbon-free energy to match our electricity consumption in all places, at all times.”
MISO President of Market Development Strategy Richard Doying said the RTO is anticipating more non-traditional membership applications like Google as more companies become enmeshed with distributed resources’ push to join wholesale markets.
The RTO’s approval of Google’s membership came a day before the company announced a $2 billion global investment in solar and wind generation across 18 new renewable energy deals.
The board also allowed Upper Peninsula Power Co. into the Municipals, Cooperatives and Transmission Dependent Utilities sector. Both applications for membership were approved unanimously.
Lurie Joins Board
The board also filled a vacant seat with former New York Power Authority CFO Robert Lurie. The selection was made without input from MISO membership, as the seat was vacated earlier in the year by Thomas Rainwater. MISO’s bylaws stipulate that vacancies are dealt with by solely the board, and not through the usual Nominating Committee process and subsequent stakeholder vote.
“We had a robust discussion of the candidates and their qualifications, and I think he will serve MISO well,” Chair Phyllis Currie said.
MISO could have seen up to four new faces on its board in 2020, but the Nominating Committee opted only for existing board members as eligible candidates: Todd Raba, Trip Doggett and Barbara Krumsiek. (See MISO Board of Director Briefs: June 20, 2019.) The RTO will again use VoteNet Solutions to conduct its membership vote on the candidates. Electronic polls are set to open Thursday for 37 days.
This year’s Nominating Committee consisted of Directors Baljit Dail, Mark Johnson and Theresa Wise; the two stakeholder seats were occupied by Minnesota Public Utilities Commissioner Matthew Schuerger and Ameren’s Jeff Dodd.
ST. PAUL, Minn. — MISO staff are done assembling the RTO’s 2019 Transmission Expansion Plan (MTEP 19), presenting a nearly $4 billion draft package to the Board of Directors last week.
Instead of concentrating solely on this year’s plan, however, MISO executives at the board’s System Planning Committee meeting Sept. 17 emphasized what changes they would make to modernize the 15-year future scenarios used annually to justify transmission projects.
The proposed 2019 portfolio — 472 new projects totaling nearly $3.9 billion — is open for stakeholder review through the end of the month. The latest draft is trimmed from an earlier version that contained 483 projects at a cost of $3.95 billion. Even with the reductions, it’s still the RTO’s second-most expensive transmission buildout. (See MISO 2019 Transmission Expansion Plan Takes Shape.)
Vice President of System Planning Jennifer Curran told the board to expect some additional changes in response to stakeholder comments.
MISO said MTEP 19 is “consistent” with MTEP 18 because the package primarily consists of reliability projects. That trend appears likely to continue in the 2020 package, as the RTO has announced it would recycle its futures next year. The RTO has promised an extensive reboot of its planning projections beginning with the 2021 portfolio. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.)
“I think [with] the status quo coming for 2020, there will be more interest in the 2021 futures,” Director Nancy Lange predicted, urging careful thought from MISO on the new futures. “I think the pace of change is only accelerating, so it’s important for MISO to think about its key planning assumptions.”
Asked by Director Phyllis Currie if there was any discord as MISO prepared MTEP 19 with stakeholders, staff cited discussions over how prominently batteries should be featured in the planning landscape.
“That’s a big focus for our team,” said Executive Director of System Planning Aubrey Johnson, adding that MISO first must create a cost recovery mechanism for storage devices.
Director Trip Doggett asked if batteries are gaining more traction because of recent technological breakthroughs or because of their transmission capabilities.
“I think it’s a ‘Yes, and…’ question,” Johnson responded, noting that batteries can mimic generation.
MISO President Clair Moeller pointed out that MTEP 19, which recommended a single battery project, anticipates just 2.5 MW of load growth. (See MISO Recommending 1st Storage-as-Tx Project.) “For perspective, 2.5 MW is the size that could be compared to a large neighborhood’s load,” he said. Moeller said that although load growth has remained flat since about 2007, load has shifted with demographics.
“So, the standard load growth isn’t driving transmission decisions. … But people are moving around,” he said.
Moeller also said differing state goals regarding their energy mixes have emerged as a planning challenge in recent years.
“When we began the [MISO] market, everyone’s fleet was about the same,” he said. “Now, not everyone thinks high wind penetration is the future. So that complicates things.”
Currie asked if neighboring RTOs were planning transmission around battery storage buildout.
“To my knowledge, we haven’t seen a strong push toward batteries,” Johnson said.
Futures Edit too Late?
Clean Grid Alliance’s Beth Soholt made use of the public comment period to call for a rework to MISO’s transmission planning strategy sooner than MTEP 21.
MISO MTEP 19-20 futures (year 2033) | MISO
She pointed to utility integrated resource plans full of renewable goals, carbon-cutting pledges from state governments and a “huge customer preference and demand for renewables” as evidence that MISO cannot afford another year of waiting before it reshapes its future scenarios.
“Over another year, we’re going to use static futures,” Soholt said. “We risk the MISO system not being able to deliver what customers want in the Midwest.”
Soholt cited MISO’s February 2017 interconnection queue cycle, where all but 250 MW of the originally proposed 5 GW of renewable generation projects dropped out because of prohibitively expensive transmission upgrades.
“The processes and the systems in MISO are misaligned to solve these challenges,” Soholt said, calling the RTO’s current planning method and assumptions “frustrating and irrelevant.” She said needed transmission projects are being overlooked because of MISO’s continued underestimation of renewable growth.
Soholt said the $32 million, 345-kV Helena-to-Hampton Corner circuit project, originally identified in this year’s Market Congestion Planning Study, should have made the cut into MTEP 19. The project was set to solve congestion in southern Minnesota, but MISO said that once forecasted wind generation was removed from the equation, the project quickly lost value.
A System from Interconnection Upgrades?
Organization of MISO States President and Missouri Public Service Commissioner Daniel Hall said the RTO is ignoring “substantial” renewable growth and expressed concern over a “number of interconnection projects dropping out very late” in the queue process. He said some renewable projects were already approved by state commissions and under power purchase agreements when they were forced to exit the queue.
“We’re currently trying to plan a transmission system one interconnection at a time. … It’s a wake-up call,” Hall told the board at its meeting Thursday.
“They’re stale,” Moeller admitted of the four futures.
“I think there’s [been] more planning and more discussion over the two years I’ve been here. … I’ve seen more coordination. I really think it’s a case of just because there’s congestion there doesn’t necessarily mean that it warrants a project to correct it,” Johnson said.
ST. PAUL, Minn. — The MISO footprint didn’t come close to its forecasted summertime peak and is unlikely to hit its forecasted fall peak either. But ways to improve resource adequacy in a time of grid transformation were on the minds of those at MISO Board Week here.
Times a-Changin’
MISO’s interconnection queue is further evidence of the urgency of its resource availability and need (RAN) project, Richard Doying, president of market development strategy, told the Markets Committee of the Board of Directors on Sept. 17. RAN ideas currently include a 30-minute reserve product, a resource accreditation rethink, a seasonal capacity auction and a multiday forecast. (See MISO, Stakeholders Debate Merits of Seasonal Auction.)
Based on utility and state announcements, MISO forecasts wind and solar generation will overtake coal and natural gas. By 2030, wind and solar will total 30 to 35% of generation output, while natural gas and coal will have 29% and 24 to 29% shares, respectively. Nuclear’s contribution is projected to be nearly halved to 9%. In 2018, MISO reported a fuel mix of 48% coal, 26% gas, 16% nuclear and 7% wind and solar combined.
Proposed solar projects currently comprise 59 GW of MISO’s 101-GW interconnection queue. Wind generation has a 27-GW share, while natural gas-fired resources represent 9 GW. Storage resources, still nascent in MISO, total only 3 GW. No new nuclear generation is proposed in the queue.
“We do expect to see more storage,” Doying told the board, adding that MISO is particularly anticipating solar-and-storage hybrids.
“I think you can get the whole community behind this,” Director Baljit Dail said, commending the RTO on RAN’s catchphrase, “All hours matter.”
Dail compared it — in rhetoric only — to 2001’s No Child Left Behind Act. Since last year, MISO has said it needs to shift from its one-day-in-10-years loss-of-load expectation to an approach that accounts for different risks across all operating hours.
“We have not considered ‘No Hour Left Behind,’” Doying laughed.
Director Barbara Krumsiek compared the RAN effort to “changing a tire [while] going 60, 70 mph on the interstate.”
Director Trip Doggett asked if NERC appeared to be also shifting from its one-in-10 reliability standard.
“It is something that lots of other folks are looking at,” Doying said.
But WPPI Energy economist Valy Goepfrich was quick to remind leadership that RAN is merely studying whether MISO needs to pivot to an all-hours risk. She said it could turn out that preparations for a summer peak still cover reliability risks in every other operating hour of the year.
“We’re letting the data drive what the peak is,” she told the board.
“It’s still that one hour that we have to meet. The problem is we don’t know when that hour is any more. It used to be a warm day in July or August. Now that’s shifted,” MISO CEO Joh Bear explained at Thursday’s board meeting.
Peak Forecasts Averted
MISO Executive Director of Market Operations Shawn McFarlane predicted that the RTO won’t hit its forecasted 112-GW fall peak, saying the highest risks of September’s heat have passed. (See MISO Unruffled by Fall Supply-demand Outlook.)
“Right now, the highest load we’ve had is 107 GW on Sept. 7,” McFarlane said.
MISO also fell short of its nearly 125-GW forecast summer peak, instead experiencing a 121-GW summer peak July 19.
MISO forecasted portfolio change | MISO
The RTO weathered a heat wave and a hurricane in July without reliability problems. It declared conservative operations on July 18 and issued an open-ended maximum generation capacity advisory effective 10 a.m. ET on July 19 as several Midwestern cities issued excessive heat warnings and heat indexes exceeded 100 degrees Fahrenheit even in Minneapolis. Both alerts were terminated July 20. MISO’s capacity advisories ask members to prepare for emergency conditions, ready load-modifying resources for a possible call-up and ensure resource availability is up to date in the RTO’s communication system.
On July 11, MISO declared a severe weather alert for its Gulf Coast region for July 12 to 15 as Tropical Storm Barry was forming over the gulf. MISO’s weather alerts ask that maintenance and testing on any critical transmission or generation system be deferred or canceled. The alert lasted through July 20 as Entergy mobilized crews to restore power in flooded portions of Louisiana.
Independent Market Monitor David Patton said the most exciting part of the summer occurred in eastern Texas on Aug. 13, when a transformer lost cooling in the West of the Atchafalaya Basin load pocket from 4 to 6 p.m.
“We were extremely close to shedding load; if there had been another contingency…” Patton trailed off.
MISO interconnection queue breakdown | MISO
Prices during the contingency spiked to $560/MWh, but just over the border in sunbaked ERCOT — which was experiencing high load — prices were $8,800/MWh
Patton said the area should have been more appropriately priced at about $4,000/MWh. He added that ERCOT prices had to be attractive to MISO members, who were prohibited from lending supply because of the RTO’s own reliability risks.
“The reliability situation was far more dire in MISO than in ERCOT,” Patton said.
He again called for MISO to “beef up” its emergency and shortage prices, especially for times when portions of the footprint are “on the verge of load shedding.”
“As we grow our intermittent sources, we’re going to see more shortages,” he warned.
The effort to expand CAISO’s Western Energy Imbalance Market from a real-time trading platform to a day-ahead market took a significant step forward Wednesday, when members of the ISO’s Board of Governors and the EIM’s Governing Body said they supported launching a stakeholder process in October.
The first step will be an issue paper. Then the stakeholder process is expected to continue well into next year, said Keith Casey, CAISO’s vice president of market and infrastructure development. It will address issues such as resource sufficiency in a tightening Western market and interstate transmission challenges, ISO staff said.
Board Chair David Olsen and EIM Governing Body Chair Carl Linvill gave their verbal support to the stakeholder process; there was no formal vote. The occasion was a briefing on the results of an eight-month feasibility study of the extended day-ahead market (EDAM).
Fourteen current and future EIM entities, in addition to CAISO, participated in the assessment.
The non-CAISO entities wrote a joint letter to ISO and EIM leaders emphasizing they have not committed to the EDAM and want to make sure it addresses a number of concerns, including the continued independence of the Governing Body and the representation of a range of interests from across the West.
A continuing worry among EIM participants is that California politicians and CAISO might try to dominate the regional market. CAISO’s bid to form a Western RTO stalled in part because CAISO’s governors are appointed by the governor and approved by the State Senate.
“The issues to be resolved to make EDAM a reality should not be underestimated,” the entities wrote. Those that signed the letter included Arizona Public Service, Idaho Power and PacifiCorp.
“Governance structures must be considered that reflect the new market design and the legitimate interests that all within the broader market footprint will have in the operation and rules of the day-ahead market,” it said. “In addition, it is likely EDAM will need to include a test to ensure that all participating balancing authorities are not leaning on neighbors to meet their continued reliability obligations.”
Estimated Benefits
A goal of the feasibility study was to estimate the financial benefits to EIM participants to gauge their potential level of interest, Mark Rothleder, CAISO vice president of market quality, told the board and Governing Body.
The EIM has continued to add new members, but some entities from the interior West have cited the economic bonuses as their primary motivation while lamenting the tie to California. The uneasy political alliance is part of the reason SPP recently launched its own Western Energy Imbalance Service. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
Rothleder said the study group and its consultants, E3 and Brattle Group, had projected the operational benefits of a day-ahead market at $119 million to $227 million annually, which he called a conservative estimate. (In their letter, the EIM entities pointed out that the estimate doesn’t consider how “benefits may be reduced should only a limited number of EIM entities elect to participate in EDAM.”)
The expected financial benefits will come partly through more efficient day-ahead hourly trading and better use of available transmission in an organized market, according to Rothleder’s presentation.
| CAISO
The EIM says its real-time market has saved participants more than $736million since it began in 2014.
A day-ahead market could limit the curtailment of excess renewable resources by up to 2 GWh a year, sending energy where it’s needed and producing tens of millions of dollars in additional revenue for generators, Rothleder said.
Environmentalists have generally supported regional markets as a way to maximize the sharing of renewable resources, for example, by sending wind energy from New Mexico to California and solar power from California to the Pacific Northwest.
Jennifer Gardner, senior staff attorney with Western Resource Advocates and a member of the committee that nominates Governing Body members, praised the move in a news release. Adding a day-ahead market to the EIM would “allow utilities to better plan for and optimize renewable energy use on the grid through more efficient unit commitment and more effective integration of variable energy resources across a larger footprint,” Gardner said.
Sarah Edmonds, transmission director at Portland General Electric, and Jim Shetler, general manager of the Balancing Area of Northern California, were part of the assessment team. They spoke at Wednesday’s meeting and acknowledged the challenges and effects of a day-ahead market that stretches across the Western Interconnection.
“This is going to be significant and complex,” Edmonds said. “It could have consequences for the Western market as a whole.”
EIM Governance Review
The board and Governing Body also named 10 members of a committee to review the governance structure of the EIM, as required by the market’s original charter. (See CAISO OKs EIM Governance Review.)
The charter recognized that the EIM would evolve over time, and the expansion to a day-ahead market could necessitate governance changes, said Stacey Crowley, CAISO vice president of external affairs.
Members named to the Governance Review Committee (GRC) included Gardner; Therese Hampton, chair of the EIM’s Regional Issues Forum and executive director of the Public Generating Pool in the Pacific Northwest; and Eric Eisenman, PG&E’s director of ISO and FERC relations.
Their colleagues nominated Governing Body member Valerie Fong and CAISO Governor Angelina Galiteva as representatives to the GRC.
Board Chair Olsen said he’s hoping to add another member from the EIM’s investor-owned utilities because he felt the committee was light on IOU representation.
The committee will eventually include 11 to 13 members, said Peter Colussy, CAISO manager of regional affairs.
FERC told MISO, PJM and SPP last week that their joint operating agreements don’t provide enough clarity on how the RTOs’ handle generator interconnections along their seams (EL18-26).
The commission agreed in part with EDF Renewable Energy and ordered the RTOs to update their JOAs and Tariffs to make the queue priority process more transparent within 60 days of its ruling Thursday. The commission declined the company’s related request (AD18-8) to expand the review of affected-system coordination in the generation interconnection process beyond MISO, PJM and SPP, however.
“Because the queue priority processes are not described in their tariffs or JOAs, we find that there is a lack of transparency in MISO, SPP and PJM that makes it difficult for interconnection customers to understand how affected-system network upgrade costs are being allocated to them,” FERC wrote. “Requiring the RTOs to detail this information in their JOAs will provide additional transparency to interconnection customers on their potential responsibility for affected system network upgrade costs, thereby reducing uncertainty that may hinder interconnection development.”
| EDF Renewable Energy
The order comes nearly 18 months after FERC staff held a technical conference with the RTOs to address the issues raised in EDF’s October 2017 complaint that their governing documents, particularly the JOAs, lack details about the timing of affected-system analyses, the standards applied to determine impacts from proposed interconnections and how network upgrade costs are assigned. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
FERC Order 2003 requires a transmission provider to coordinate interconnection studies and planning meetings with affected systems — electric systems other than the host transmission provider that may be affected by a proposed interconnection.
EDF argued that the lack of clarity regarding the RTOs’ delivery requirements and modeling standards violates the commission’s requirement for transparent, open-access interconnection service.
FERC said that despite insistence from the RTOs to the contrary, their existing documents lack transparency and cause “harm due to uncertainty” for EDF and other interconnection customers who struggle with decisions about whether to remain in the queue for fear of incurring unknown costs.
“Cost uncertainty presents a significant obstacle to the development of new resources, as some interconnection customers are less able to absorb unexpected and potentially higher costs for interconnection facilities and network upgrades that may occur once affected-system study results are considered,” FERC wrote. “This lack of transparency in the current affected-systems coordination process between MISO, SPP and PJM has the potential to hinder the timely development of new resources and thereby to stifle competition in the wholesale markets, resulting in rates that are not just and reasonable or are unduly discriminatory or preferential.”
The commission, however, rejected EDF’s request that the RTOs unify their modeling systems and study timelines, deeming neither necessary for providing greater transparency.
The RTOs’ compliance filings must include:
Current affected-system coordination processes, including the provision of clear references to where affected-system study information can be found in their business practice manuals;
A description of the modeling standard (external resource interconnection service or network resource interconnection service) they use to study, as the affected RTO, interconnection customers that request ERIS in the host RTO and interconnection customers that request NRIS in the host RTO;
The location in their manuals or other coordination documents where interconnection customers can find the modeling details that they use when studying a project as ERIS or NRIS for interconnection requests on their own systems;
For MISO and SPP specifically, a description of how they study the impacts on the affected RTO and clarify that the each RTO’s study criteria apply to its own facilities;
How the three RTOs monitor each other’s systems during the course of each of their interconnection studies;
PJM’s process for monitoring neighboring systems for affected-system impacts; and
PJM’s timeline provided to interconnection customers to review affected-system study results.
SPP’s dream of operating an energy market in the Western Interconnection came closer to reality Friday with its Board of Directors’ approval of start-up funding for the Western Energy Imbalance Service (WEIS) market.
The board accepted staff’s recommendation to budget $9.5 million to develop and stand up the market. The Members Committee supported the recommendation, with only Xcel Energy’s Southwestern Public Service abstaining from the vote during a conference call.
Committee members peppered SPP staff with questions about the proposal’s costs to existing members and whether the RTO will maintain a division between Eastern and Western members. Staff assured members there will be no increase to corporate overhead.
Asked how the market will help “East-side members,” Senior Vice President of Operations Bruce Rew said current members would benefit from the “additional use of the SPP system.”
“That will provide additional revenue through corporate overhead costs and reduce the SPP administrative fee accordingly,” Rew said.
Staff said they have been tracking expenses to develop the market proposal and will continue to do so. The RTO said it will add 13 employees to perform the WEIS functions and will begin the hiring process “as soon as practical.”
“We have a 16-month schedule, and there’s a lot of work to be done,” Rew said.
SPP says it will finance the costs during the implementation period by issuing debt. It will then recover the costs from the WEIS participants over eight years, beginning in December 2020, using a formulized rate that includes projected annual production costs, start-up principal and interest charges, and current net energy for load.
Market participants who terminate WEIS services within the first eight years are obligated to pay their portion of the remaining implementation costs. Additional participants who enter the market within that period will be allocated a portion of the original implementation costs.
The WEIS will operate similarly to SPP’s imbalance market, which ran from 2007 to 2014, centrally dispatching energy on a five-minute basis under a Western joint dispatch agreement. Members will operate under a separate tariff and market protocols from SPP’s Eastern Interconnection members. Should a WEIS member decide to join the RTO as a transmission owner, the balance of its implementation costs would be spread out among the market’s remaining participants.
SPP has long explored offering market services in the Western Interconnection and seeking new members. An effort to integrate the Mountain West Transmission Group fell apart last year, but the grid operator’s attempt to provide reliability coordination services to 12% of the region’s load is on schedule to meet a December timeline. (See SPP Western Reliability Briefs: Week of Sept. 16, 2019.)
The WEIS market will become the West’s second, joining CAISO’s Western Energy Imbalance Market.
SPP says the WEIS will go live in February 2021. It already has five market participants in Basin Electric Power Cooperative, Tri-State Generation and Transmission Association, and three Western Area Power Administration entities: Colorado River Storage Project, Rocky Mountain Region and Upper Great Plains. All five organizations signed contracts in September to fund the market’s development. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
The grid operator said it will accept additional participants through Oct. 25. Market participants who want to join the WEIS after that date will be onboarded through SPP’s normal processes.
Xcel, Colorado’s largest load-serving entity, and three partners — Black Hills Energy, Colorado Springs Utilities and Platte River Power Authority — have announced they are evaluating both the WEIS and the EIM. (See Colorado Utilities Examine Market Membership.)
SPP made the WEIS public in June, distributing a proposal to 19 interested parties in the interconnection.
It expects to file a WEIS Tariff with FERC early next year. Legal staff said they were not aware of any necessary state regulatory filings.
In a major setback for developers of small power projects, FERC on Thursday launched a rulemaking to overhaul its regulations under the Public Utility Regulatory Policies Act, the 1978 federal law enacted to spur competition in the U.S. electricity sector (RM19-15, AD16-16).
Thursday’s Notice of Proposed Rulemaking signals the commission is aiming for top-to-bottom changes to PURPA, including elimination of a fundamental principle of the rules: fixed-price contracts for qualifying facilities (QFs).
In seeking the changes, FERC is responding to longstanding complaints about PURPA by utilities and the state commissions that regulate them. But the commission has also roused the objections of PURPA supporters and its lone Democratic member, Commissioner Richard Glick, who in a partial dissent said the NOPR would “effectively gut” the regulations.
FERC ruled in 2016 that Entergy did not have to purchase power from Occidental Chemical’s Taft plant in Louisiana because the PURPA generator had unconstrained transmission access and could sell its output in the MISO wholesale market. | Occidental Chemical
In a statement accompanying the NOPR, FERC called the effort its “first comprehensive review” of the regulations since they were implemented 39 years ago.
“It’s clearly time for FERC to revisit its PURPA policies,” Chairman Neil Chatterjee said. “Congress told us to review our policies from time to time to ensure that our regulations continue both to protect consumers and to encourage the development of QFs. That is precisely what we are doing here.”
But in his dissent, Glick said the NOPR suggested that FERC “no longer believes that PURPA is necessary” and warned that it is encroaching on Congress’ authority.
“Whether PURPA’s goals remain relevant is a decision for Congress, not an administrative agency. The commission should not be seizing the reins from Congress in order to isolate an important debate about national energy policy within an independent regulatory agency,” Glick said.
Avoiding Avoided Cost
Chatterjee’s words of assurance about QFs notwithstanding, QF developers appear to have much to lose from the outcome of the NOPR. The proposal closely aligns with a set of PURPA recommendations that the National Association of Regulatory Utility Commissioners floated nearly two years ago after complaining about the time and expense of administering PURPA projects. Many commissions have long sought to rein in the volume of PURPA projects, particularly in Western states. (See NARUC Calls for PURPA Reforms, Outlines Proposed Changes.)
Reflecting one of NARUC’s key priorities, the NOPR zeroes in on what is sacred ground for QF developers: PURPA’s requirement that utilities contract with small projects at a fixed “avoided cost” rate — or the incremental cost a utility would have to pay to generate power itself.
QF developers say that requirement is vital to their financial viability, ensuring they receive ample and predictable compensation for their output over a contract period. But utilities and regulators complain that the avoided-cost calculations currently used to set contracts increasingly exceed the steadily declining costs of power available in open markets, unjustly adding to the bills of ratepayers.
Larry Greenfield, of FERC’s Office of General Counsel, answered questions on the commission’s proposed PURPA changes.
While the NOPR wouldn’t erase PURPA’s avoided-cost provision, it would upend the current rules by eliminating the notion of fixed-cost contracts. FERC says it would provide “flexibility to state regulatory authorities so they can accommodate recent wholesale power market developments.” That flexibility would extend to granting states the ability to:
Require that energy rates — but not capacity rates — in QF power sales contracts vary according to changes in the purchasing utility’s avoided costs at the time the energy is delivered.
Allow QFs to retain their rights to fixed energy rates, but to base them on projections of what energy prices will be at the time of delivery during the term of a QF’s contract.
Set energy and capacity rates based on competitive solicitations conducted in a transparent and nondiscriminatory manner.
The NOPR also proposes to allow state regulators to use LMPs to set the “as available” QF energy rates for resources selling into RTOs/ISOs — or to use competitive prices from liquid hubs to set those rates in areas without organized markets.
In his dissent, Glick expressed concern that elimination of fixed-price contracts “will make it more difficult — or in some cases impossible — for QFs to obtain financing. The option to enter a contract with a fixed or known price has played in essential role in encouraging QF development.”
Glick also contended that the contracts “have played an important role in ensuring that QFs receive nondiscriminatory rates, especially in areas of the country with vertically integrated utilities that are guaranteed to recover the costs of their prudently incurred investments through retail rates. Neither the record nor the rationale in this NOPR addresses these concerns in a manner that is even remotely convincing.”
The NOPR takes up yet another NARUC recommendation in proposing to modify PURPA’s “1-mile rule,” which is used to determine whether affiliated QFs located proximate to each other should be considered part of a single larger facility. Regulators in the interior West have complained that large developers have “gamed” the rule by parceling large projects in such a way that they unjustly earn PURPA treatment. (See PURPA Critics Call for Reforms.)
While the commission proposes to maintain the “irrebuttable” presumption that facilities 1 mile apart or less constitute a single facility, it calls for giving states the latitude to determine that facilities located more than 1 mile apart, but less than 10 miles apart, could comprise a single facility. Facilities 10 miles apart or more would still benefit from the irrebuttable presumption that they are separate facilities.
The NOPR additionally proposes to eliminate the “rebuttable” presumption that QFs with a net capacity at or below 20 MW don’t have nondiscriminatory access to certain markets, replacing that threshold with 1 MW. One exception: The threshold for cogeneration facilities would remain at 20 MW.
FERC is also seeking to require states to establish objective and reasonable criteria to determine a QF’s commercial viability and financial commitment to construction before it is entitled to a contract or legally enforceable obligation. It would also allow an entity to protest a QF self-certification or self-recertification without having to file and pay for a declaratory order.
‘Meaningful Evolution’
FERC’s newest member, Commissioner Bernard McNamee, issued his own statement in support of the NOPR.
“The changes the commission is proposing through this Notice of Proposed Rulemaking are designed to protect consumers while also encouraging the development of alternative generation and cogeneration facilities,” McNamee said. “To achieve these ends, the proposed rules will provide state utility regulators more flexibility to rely on market pricing when determining the rates utilities pay to qualifying facilities under PURPA, provide more transparency to interested stakeholders, and extend the benefits of competition to a greater number of consumers.”
Joshua Kirstein, of FERC’s Office of General Counsel, summarized the commission’s PURPA ruling at Thursday’s open meeting.
Support came from other corners of the power sector as well.
“We applaud FERC Chairman Chatterjee for his leadership and for prioritizing PURPA reform,” Edison Electric Institute President Tom Kuhn said. “By initiating this important NOPR, Chairman Chatterjee has reaffirmed that there are concrete steps FERC can take to better protect electricity customers from unnecessary energy costs and drive additional investments in renewable energy, all while meeting the commission’s responsibilities under the act.”
American Public Power Association CEO Sue Kelly said the electricity sector has undergone a “meaningful evolution” in its resource mix since PURPA’s enactment. “We applaud FERC for recognizing the need to ensure that PURPA’s implementation is aligned with today’s energy landscape,” she said.
“Today’s vote was a much-needed first step in the process of modernizing PURPA,” National Rural Electric Cooperative Association CEO Jim Matheson said. “FERC’s rules implementing PURPA today promote the uneven, unplanned and uneconomic development of facilities and provide subsidies that promote these facilities at the expense of our members, system reliability and other more affordable resources.”
The Electricity Consumers Resource Council (ELCON) was more measured in its endorsement of the NOPR, saying that it supports “thoughtful reform” of the 1-mile rule and “improving avoided cost estimates,” while applauding FERC for recognizing that cogeneration facilities are “unique” among QFs. But the group also emphasized that PURPA still plays an “essential” role in encouraging competition.
“The majority of states remain under cost-of-service regulation, where industrial self-supply and competitive power generation face uncompetitive conditions both within and outside of organized wholesale electricity markets,” ELCON CEO Devin Hartman said. “It is imperative that FERC proceed in a manner that enhances competition and reduces barriers to self-supply in regulated states, whereas loosening PURPA implementation would run counter to FERC’s stated intent of protecting consumers and preserving competition.”
Renewable advocates expressed disappointment in Thursday’s development.
“Rather than focusing on PURPA’s goal of ensuring competition, this proposed rule will have the effect of dampening competition and allowing utilities to strengthen their monopoly status,” said Katherine Gensler, vice president of regulatory affairs for the Solar Energy Industries Association. “The proposed rule is a move away from competition, and we hope FERC rethinks the most harmful portions of this proposal. We will continue to push for PURPA reforms that increase competition, transparency and enforcement.”
Comments on the NOPR will be due 60 days after its publication in the Federal Register.
FOLSOM, Calif. — CAISO’s Board of Governors on Wednesday heard that the ISO could face capacity shortages as soon as next year if steps aren’t taken to address the potential shortfall, including keeping aging natural gas plants from retiring as planned.
In a presentation to the board, CAISO Vice President Mark Rothleder said summer peak demand is shifting from late afternoon to early evening. People now are going home and turning on their air conditioning around 7 p.m., just as solar power peters out, he said.
“The issue is not so much at the peak hour,” Rothleder said. “It’s at the near-peak hour as the sun goes down.”
By next summer there could be insufficient capacity to meet the ISO’s system reliability requirements, which include a 15% planning reserve, Rothleder said.
Imports that aren’t already under contract could fill the gap, but tightening supply in the West makes those imports unreliable. California’s neighbors are using more of their own electricity instead of exporting it, he said.
Rothleder said the shortages could start in the hot summer days of 2020 with a 2,300-MW shortfall at 7 p.m., increasing to 4,400 MW in 2021 and 4,700 MW in 2022. The problem could worsen when Pacific Gas and Electric’s Diablo Canyon Power Plant, the state’s last nuclear generating station, shuts down in phases starting in 2024, he said.
California is on an ambitious push to use carbon-free energy, but to avoid a crisis it may be necessary to prevent older natural gas peak plants from shutting down, Rothleder told the board.
“We’ve got the last tranche of once-through cooling scheduled for retirement” near the end of 2020, Rothleder said. Those plants can generate about 4,000 MW, he said.
Once-through-cooling (OTC) plants are being phased out because they use water from oceans and estuaries, killing billions of marine organisms including fish larvae and shellfish, according to the California Energy Commission.
“We need to get on the track of procurement” to generate more energy, Rothleder said.
CAISO said there could be a resource shortage in the next two years. | CAISO
Increasing wind and geothermal energy production, and adding more short- and long-term storage, would provide energy after sundown without greenhouse gases, he said.
In public comments Wednesday, speakers encouraged the board to move quickly to address the resource adequacy problem.
“We urge the ISO to continue to work on this expeditiously. Soon. Now. Not later,” said Eric Eisenman, PG&E’s director of FERC and ISO relations.
Board Chair David Olsen responded, “This is obviously our top priority. Front and center for us.”
Edward Randolph, director of the California Public Utilities Commission’s Energy Division, told the board that the commission also is acting on the threat.
“We do take what is being raised here today pretty seriously,” Randolph said.
On Sept. 12, a CPUC administrative law judge issued a proposed decision requiring load-serving entities in Southern California Edison’s service area to procure 2,500 MW of additional resources between August 2021 and August 2023. ALJ Julie Fitch also recommended keeping the OTC plants operating, a decision that’s ultimately up to the state Water Resources Control Board.
“Procurement shall be conducted on an all-source basis, including both existing and new resources, and may include LSE-owned resources when justified,” Fitch wrote.
“The commission should act now to forestall a potential system reliability emergency by 2021 and require ‘least regrets’ actions with respect to OTC deadlines and LSE procurement,” she said.
The CPUC could vote to adopt the decision as early as Oct. 24, it said.
MINNEAPOLIS — NERC’s Stakeholder Engagement Team (SET) has agreed to expand the membership of the new committee that would replace the Planning, Operating and Critical Infrastructure Protection committees, stakeholders were told last week.
SET member Lloyd Linke, of the Western Area Power Administration, told a joint meeting of the OC and PC that the new Reliability and Security Council (RSC) will have 34 voting members: two each from Sectors 1-10 and 12, for a total of 22; 10 at-large members, a chair and a vice chair. The committee will also have five nonvoting members, including a NERC staffer as secretary, along with two U.S. federal representatives, and two Canadian representatives: one federal and one from the provinces.
If a sector does not have two members, the vacant slot will be filled by an additional at-large member to keep the total at 34 members.
The RSC will be only about a quarter of the size of the three technical committees it will replace, which have almost 120 voting members. But the SET’s original plan called for only one member from each sector, a proposal that met opposition. (See NERC Board Hears Debate over Committee Reorg.)
Linke also said the RSC meetings will be open to other stakeholders.
He said the move was driven by a desire for a “better functional alignment” between the technical comms and the Reliability Issues Steering Committee (RISC). Reducing travel and hotel costs “wasn’t a primary driver,” he said. “It wasn’t a big driver at all.”
The RSC members will have three- and two-year terms initially, then revert to staggered two-year terms. Once the committee is set up, the RSC nominating process will follow the model of the Compliance and Certification Committee.
Linke said one of the initial tasks of the RSC will be determining how to continue the “lessons learned” sharing and awareness functions used by the technical committees.
“We don’t want to lose that engagement,” said John Moura, NERC director of reliability assessment and technical committees. Concerns about the potential loss of functions “hit [NERC] staff strongly,” he said.
The SET rejected suggestions that the technical committees evaluate their subcommittees to determine their future. “There was a desire not to tie the hands of the new RSC,” Linke said.
The schedule calls for the RSC to hold its first meeting in March along with the three technical committees, which would end their operations effective June 1.
Some members expressed opposition to the proposed committee merger after the OC and PC split for their separate meetings.
“I don’t think the new structure is going to have the amount of expertise or dedicate as much time as [the technical committees] do,” Peter Brandien, vice president of systems operations for ISO-NE, said at the PC meeting.
“I think the most important aspect of this plan is the change of this legislative structure from one that is wholly elected to one that is partly elected and partly appointed. The world’s currently best-known example of that kind of legislature is Hong Kong,” said Robert Blohm, managing director of Keen Resources. “That’s my comment.”
SPP’s efforts to extend reliability coordination services to about 12% of the Western Interconnection’s load remains on a glide path, staff said this week during a pair of meetings with Western entities at Black Hills Energy’s offices in Rapid City, S.D.
The RTO is preparing for the start of shadow operations and a second certification visit by regulatory representatives in October. It plans to go live with RC services in the West on Dec. 3.
C.J. Brown, SPP’s director of system operations, told the Western Reliability Executive Committee on Wednesday that the grid operator is focused on closing issues identified by a Western Electricity Coordinating Council-led certification team’s August site visit. (See Certification Team Checks SPP’s Western RC Function.)
“Everything is on track,” he said.
The team did not find any “showstoppers,” Brown said, but left behind several issues it felt SPP needs to resolve before going live. Staff expect to close those issues by October and are on track to close about 40% of “recommended” issues before the certification team’s return visit on Oct. 9.
By then, SPP will have begun two months of shadow operations with Peak Reliability, WECC’s incumbent RC. Peak said in August 2018 it would wind down operations by the end of this year. SPP, CAISO RC Wins Most of the West.)
Shadow ops begin on Oct. 7, but SPP operators will begin staffing the RC desk on Sept. 25. A shadow ops model is expected to be in production on Oct. 1.
Brown said SPP staff have received a separate request from WECC, FERC and NERC staff to visit the RTO’s Arkansas headquarters in early November. The agencies conducted a similar visit to CAISO’s RC West.
“If it’s a good idea for California, it’s a good idea for SPP too,” Brown said.
| SPP
Tri-State Generation and Transmission’s Keith Carman, chair of the WREC, offered words of praise for Peak employees, who have been working closely with staff from the incoming RCs.
“These employees have been nothing but professional, responsive, kind and receptive,” Carman said. “It’s way unexpected too, considering the predicament they’re in.”
RCs have been compared to top cops for transmission reliability across wide geographic areas. They are responsible for ensuring each member focuses on reliability, particularly across the seams from one area of responsibility to the next.
Brown also briefed the NERC Operating Committee on the RC transition last week, telling members said SPP “will be more proactive” in November before going live at noon MT on Dec. 3.
SPP’s Yasser Bahbaz told the Western Reliability Working Group it has received more than 10,000 inter-control center communications protocol (ICCP) data points from CAISO as it works to stand up its western RC model. Staff is currently validating about 4,000 of those points, which changed from Peak’s model to CAISO’s.
“Someone made a change from an old name to a new name,” Bahbaz said. “We’re having to go one-by-one to reconcile.”
Brown said the CAISO model will become SPP’s primary model, with an earlier Peak model becoming secondary.
SPP has also downloaded Peak’s outage data into its systems and was to spend this week validating software applications with Peak’s balancing authorities. The RTO has already completed ICCP connectivity with its 13 RC customers.
SPP has ‘Good Handle’ on Reserve Sharing Groups
SPP is not concerned with “special circumstances” surrounding reserve sharing groups (RSGs) in the West, Brown told the WRWG. RSGs consist of two or more BAs that collectively maintain, allocate and supply operating reserves for use in recovering from contingencies within the group.
The Northwest Power Pool’s RSG has reserve requirements for the Western Area Power Administration’s Colorado and Missouri (WACM) region’s BA, while other WACM entities are part of the Southwest Reserve Sharing Group.
“I believe we have a good handle on the RSGs,” Brown said. “It’s pretty basic. We run one.”
SPP is working to receive contingency reserve data from the NWPP and Bonneville Power Authority RSGs. It plans to soon request the contingency reserve data for each BA within its RC footprint.
“We want to ensure every resource is covered by an RSG or a reserves requirement,” Brown said. “We just want to know how it’s done in the West. We want to understand the situation, so we have [it] accurately modeled.”
Brown said SPP would only issue energy emergency alerts in the West for reliability concerns. BAs will be responsible for meeting NERC’s BAL-002 requirements.
“We don’t expect anyone to shed load for a compliance violation,” he said.
WREC Approves Doc Modification Process
The WREC unanimously approved a modification oversight process (MOP) to manage document modifications related to the RTO’s Western RC services. The WRWG had been working to finalize the document since May.
The MOP applies to documentation established by SPP or SPP working groups that might affect operations or have a compliance or financial impact on its Western RC services customers. (See “SPP’s MOP ‘Cleans Up Stuff,’” SPP Western Reliability Briefs: Week of May 13, 2019.)
