Page 1422 – RTO Insider

July 25, 2016

With Oncor Back on the Market, Multiple Suitors Line Up

By Tom Kleckner

Interest in bankrupt Energy Future Holdings’ Texas transmission and delivery subsidiary Oncor continues to grow, even as the troubled company struggles to emerge from Chapter 11 without a massive tax bill.

NextEra Energy and Berkshire Hathaway Energy are thought to be the leading contenders for Oncor, the largest utility in Texas with 119,000 miles of lines and more than 3 million meters. Fidelity Management, Edison International and Hunt Consolidated — which saw its bid for Oncor fall apart in May — are among those whose names have also been floated in recent weeks as potential suitors.

In addition, the investor group led by Borealis Infrastructure Management and Singapore’s GIC Special Investments, which together own 19.75% of Oncor, is also interested in acquiring the whole company, according to Bloomberg.

Florida-based NextEra walked away from its proposed $4.3 billion purchase of Hawaiian Electric Industries after Hawaii’s Public Utilities Commission voted against it July 15. (See NextEra Said to be Leading Candidate for Texas’ Oncor.)

According to media reports, the Hunt group and others have been working to garner support in Austin.

“It is no surprise that other parties are participating in this contest, but we are working with all stakeholders to maintain our position as a very viable option for Oncor, its employees, customers” and the Public Utility Commission of Texas, Hunt Consolidated spokesperson Jeanne Phillips said in a statement.

The Hunt group in June filed a lawsuit against the PUCT, asking the commission to reverse a March order that set conditions on its bid, including a requirement to share potential tax savings with the utility’s ratepayers. (See Hunt Reopens Oncor Bid in Lawsuit Against PUCT.)

EFH, which has been in Chapter 11 for two years and is burdened by almost $50 billion in debt, has said it now wants to spin off Oncor tax-free. It is expecting a positive tax ruling this week from the Internal Revenue Service, which would eliminate a potential $4 billion tax liability. Oncor has been valued as being worth as little as $17 billion and as much as $23 billion.

The holding company was to file a plan for Oncor by July 8 with the U.S. Bankruptcy Court for the District of Delaware. Instead, it told the court it was in discussions with “multiple interested parties regarding a potential transaction” and asked for an extension.

EFH has proposed a separate path for its Luminant generation arm and TXU Energy retailer, selling them to senior creditors who are owed $24.4 billion. Hearings are scheduled to begin Aug. 17 in Delaware.

July 25, 2016

ERCOT Discusses Wind Integration at GCPA Luncheon

By Rory D. Sweeney

AUSTIN, Texas — Wind energy is quickly becoming a dominant force in ERCOT’s resource mix, and the grid operator is making changes to address it.

Speaking to a packed house at a Gulf Coast Power Association luncheon last week, Kenan Ögelman, ERCOT’s vice president of commercial operations, said ERCOT is adding a desk in its control room to monitor renewables and rethinking its ancillary services needs.

“That’s how big a deal this is both in terms of managing the system conditions and giving the correct response to what happens,” he said. “We feel we need people dedicated to watching that.”

Fast response, rapid ramping and managing inertia are the biggest needs, he said.

Wind production on ERCOT’s system surpassed nuclear production in 2015 and its growth curve is “more exponential than linear,” Ögelman said.

Kenan Ögelman, vice president of commercial operations at ERCOT, discusses the dominance of wind on his system at the GCPA's July luncheon in Austin. — Kenan Ögelman, vice president of commercial operations at ERCOT, discusses the dominance of wind on his system at the GCPA’s July luncheon in Austin. © *RTO Insider*

“The mix of resources is changing,” he said. “The characteristics of those resources is also different than what we had previously, so doing business as we had — as far as ERCOT goes — is different.”

ERCOT’s ancillary services were designed in the 1990s and assumed heavy reliance on gas cogeneration facilities.

Its reliability unit commitment, for example, reimburses unused units but is capped and doesn’t allow for recovering all costs, Ögelman said. The current market isn’t pricing that service efficiently, which is sending inappropriate pricing signals, he said.

Chief among ERCOT’s needs is maintaining reliability. Although ERCOT’s wind-speed data date back to the 1950s, monthly output can vary unpredictably. However, as the lowest-cost resource on the system, wind tends to be dispatched, Ögelman said.

While not a problem during high demand, it becomes one during the spring and fall shoulder periods when load is low and wind makes up a high percentage of dispatched generation. Because wind output can change dramatically, ERCOT has to manage the risk that it might disappear.

This is further complicated by the fact that it’s hard to keep non-renewables operating during low loads. The abundance of wind — running because production tax credits offset uneconomic bids — have increasingly resulted in negative prices on the system from midnight through 5 a.m., Ögelman said.

“The market is saying you have to pay to stay on,” he said.

So with generation at risk of suddenly disappearing and the market providing no incentive to diversify sources, ERCOT is seeking solutions. The process starts with more information to develop better models and forecasts. For example, some risk can be mitigated, he said, by diversifying where the intermittent generation comes from on the system. Wind resources from the three main regions — the panhandle, West Texas and the Gulf Coast — tend to provide wind supply at different times and can balance each other out. For solar, the movement of the sun across the system requires an extra hour in the morning to reach full capacity, but offers an extra hour in the afternoon.

Another challenge is that low load combined with low inertia gives the system no way to recover from disturbances, raising the threat of cascading outages, Ögelman said.

ERCOT performed a “future ancillary services” study, which found that the inertia need will vary based on the capacity of combined cycle units on the system, which provide twice as much inertia as other sources. As economical as they are, even combined cycle units can be forced offline with high enough wind penetrations.

Generation units with governors or other frequency-control devices provide automatic systemwide frequency response. However, as wind pushes them off the system, that service disappears. ERCOT is also looking at how to incentivize load, which can respond quickly and then return to normal. Frequency response provided by the load, Ögelman noted, can be more valuable than that coming from generators.

ERCOT plans to talk to stakeholders at the Technical Advisory Committee about ancillary services to see if needs can be met with market design features that stakeholders want. It will also look into how best to analyze inertial service. The tools exist, Ögelman said, but aren’t fine-tuned to what’s optimal for a market design and reliability standpoint.

The amount of intermittent resources on the system can continue to increase, he said, as long as they agree to be curtailed as necessary.

[Editor’s Note: An earlier version of this story incorrectly reported that wind production surpassed nuclear production on ERCOT’s system in 2014.]

July 25, 2016

Maine PUC Endorses Gas Pipeline Contracts

By William Opalka

Disregarding its staff’s recommendation, Maine’s Public Utilities Commission on Tuesday endorsed a plan in which electric ratepayers would help finance natural gas pipeline expansion (2014-00071).

PUC staff said last month that ratepayer subsidies were unnecessary because market conditions have changed dramatically since 2013, when the proposal was first made. (See Maine PUC Staff Advises Against Pipeline Contracts.)

The vote to ignore the staff recommendations was unanimous. The order includes a proviso that four other New England states considering similar financial support would have to follow suit for Maine’s participation. Only Massachusetts regulators have made that commitment so far and that decision is being challenged in court. (See More Pipelines for New England: ‘Gold-plating’ or Necessity?)

“There are so many more things that need to happen before a shovel gets turned or more gas begins to flow, and most of those things are outside of Maine’s control,” Tim Schneider, Maine public advocate, told the Bangor Daily News. He also opposed the staff recommendation.

The commission said they have determined the benefits of new pipeline capacity outweigh any costs.

Yet to be determined are those costs or when supply contracts might be signed. Under state law, any action would require written approval from Gov. Paul LePage.

“The fossil fuel industry hoodwinked the PUC into gambling $1 billion of Mainers’ hard-earned money on a massive new gas pipeline,” Conservation Law Foundation attorney Ben Tettlebaum said in a statement. “From Day One, this LePage-appointed commission has been desperate to find any way to justify overwhelming concessions for Big Gas, no matter the cost.”

The approval comes after the cancellation earlier this year of the Northeast Energy Direct expansion project. The largest remaining proposal is the Access Northeast project, which would increase natural gas capacity from New York to Maine. A related proposal before FERC to allow local distribution companies to sell natural gas to utilities for power generation is being opposed by some power plant owners. (See Generation Owners Seek to Block EDC-Pipeline Deals.)

July 25, 2016

FERC Proposes Adopting NAESB Standards

By Rich Heidorn Jr.

FERC last week issued a Notice of Proposed Rulemaking to incorporate in its regulations the North American Energy Standards Board’s latest Standards for Business Practices and Communication Protocols for Public Utilities (Version 003.1) (RM05-5-025).

NAESB’s new standards were adopted by its Wholesale Electric Quadrant (WEQ) and filed with the commission last October.

The commission also said it would list NAESB’s updated Smart Grid Business Practice Standards (WEQ-019) in its General Policy and Interpretations for guidance.

Version 003.1 updates earlier versions of nine standards covering such things as definitions of terms and Open Access Same-Time Information System (OASIS) standards.

It also adds a new standard establishing the Electric Industry Registry to replace the NERC Transmission System Information Networks as the tool to be used by wholesale electric markets to conduct electronic transactions via e-Tags.

The commission declined to adopt a second set of new standards, Modeling Business Practice Standards (WEQ-23), which specifies requirements for calculating available transfer capability (ATC) and available flowgate capability (AFC).

The standards were designed to complement NERC’s proposed retirement of its “MOD A” reliability standards. NERC has proposed replacing its six MOD A standards with standard MOD-001-2, focused exclusively on the reliability aspects of ATC and AFC.

The commission declined to incorporate the standard because it is still considering NERC’s proposed retirement of its ATC-related reliability standards (RM14-7) and is considering changes to the calculation of ATC (AD15-5). The commission said it will consider the NAESB standards as part of the ATC dockets.

The commission also said it would not incorporate:

Standards of Conduct for Electric Transmission Providers (WEQ-009), because it is only a placeholder for future standards; and
Contracts Related Standards (WEQ-010), because it contains an optional NAESB contract regarding fund transfers that is not required by the commission.

July 25, 2016

Solar Poised for Texas-sized Growth in ERCOT

By Rory D. Sweeney

HOUSTON — Texas, which ranks 10th in installed solar capacity among the states, boasts two assets that could see it rise in the rankings.

“We have a lot of sun and a lot of land,” Christine Wright, SolarCity’s deputy director of policy and electricity markets, told a Gulf Coast Power Association luncheon last week. “Those are two key things there that make Texas a great resource for solar.”

GCPA_Houston---content-(RTO-Insider) - ercot texas solar — Christine Wright, the deputy director of policy and electric markets at SolarCity, speaks during the GCPA luncheon in Houston on Thursday. Solar capacity is making great strides in Texas. © *RTO Insider*

Installed solar capacity is growing at a rate of 50% annually, and every time the world’s solar power doubles, the cost of photovoltaic panels falls 26%. In the 15 years since 2000, the industry’s share of generation capacity has doubled seven times, and the average cost for a solar facility in the U.S. was cut more than two-thirds to roughly $3/W.

Although Texas ranks first among states in solar potential, it has only 534 MW installed, putting it behind California, Arizona, North Carolina, New Jersey, Nevada, Massachusetts, New York, Hawaii and Colorado. The state saw $372 million in solar investment in 2015, which was a 48% increase over 2014 spending. While top-ranked California has nearly 25 times more installed capacity than Texas, Wright said ERCOT expects solar capacity to grow by a factor of 50 by 2030.

Wright said the driving forces are cost stability and customers’ demand for independence from the grid. Since solar incurs very few costs after installation and no fuel expense, it can act as a hedge against increasing energy bills. Wright referenced a 2015 Gallup poll that found approximately 80% of respondents preferred more emphasis be put on developing solar infrastructure.

Tax incentives add to the appeal. Congress extended the solar investment tax credit through 2023, and the state’s property-assessed clean energy program allows local governments to help residential and commercial applicants to secure loans for solar projects in exchange for an increased property tax assessment.

The state has enacted favorable legislation, Wright said, such as SB1626, which reduces builder restrictions on solar development, and HB706, which simplifies property tax form filing. But “we have seen that policymakers in other states don’t always make decisions that are consistent with customer demand,” which is why she said the industry needs to maintain an active education campaign. In Nevada, for example, rooftop solar drove $833 million in investment in 2015 but ground to a near halt after the state Public Utilities Commission promulgated rates that increased the bills for solar customers by more than 50%, she said.

She acknowledged that issues will arise as the industry gains market share, but that they are known. Efforts are being made to collect necessary data and address “growing pains,” she said, citing ERCOT’s formation of the Distributed Resource Energy and Ancillaries Market Task Force.

July 25, 2016

FERC Issues Ride-Through Requirement for Small Generators

By Rich Heidorn Jr.

Generators under 20 MW will be required to ride through abnormal frequency and voltage events under a revised pro forma small generator interconnection agreement approved by FERC last week (RM16-8).

The commission already requires generators interconnecting under the large GIA to meet such requirements.

“It would be unduly discriminatory not to also impose these requirements on small generating facilities,” the commission said, noting that technology now available to small generators, such as smart inverters, gives them the capability to comply.

The revisions require small generators to not disconnect automatically or instantaneously from the transmission system for under- or over-frequency conditions and under- or over-voltage events. “The specific ride-through settings must be consistent with good utility practice and any standards and guidelines applied by the transmission provider to other generating facilities on a comparable basis,” the commission said.

The commission said its order reflected input received in response to its March Notice of Proposed Rulemaking. (See FERC Issues Reliability Orders on Relays, Small Generators.)

FERC said its action was warranted by the increase in grid-connected solar PV generation and generator interconnection requests driven by state renewable portfolio standards.

It cited NERC’s finding that “a lack of coordination between small generating facilities and reliability standards can lead to events where system load imbalance may increase during frequency excursions or voltage deviations due to the disconnection of distributed energy resources, which may exacerbate a disturbance on the bulk power system.”

July 25, 2016

FERC Issues Revised Connected Entity, Data Collection Proposal

By Michael Brooks

WASHINGTON — Responding to a flood of criticism, FERC last week revised its proposed rules for collecting data from market-based rate traders to monitor against market manipulation, narrowing the definition of “connected entity” and streamlining the collection process (RM16-17).

The commission issued a new Notice of Proposed Rulemaking at its open meeting, abandoning a NOPR issued last September that would have required RTOs and ISOs to register market participants through common alpha-numeric identifiers, with lists of their connected entities and a description of their relationships (RM15-23).

The new proposal aligns the definition of a “connected entity” with existing MBR affiliate definitions, eliminating references to stock and ownership thresholds. The original NOPR had included as connected entities companies controlling more than 10% of another, as well as top executives and traders, a definition heavily criticized by stakeholders.

The revised definition would limit relationship reporting to only those entities engaged in FERC-jurisdictional markets and those that trade energy transaction derivatives. The new proposal also would not require reporting debt instruments or structured transactions and submitting organizational charts.

The new NOPR also adopts changes in a December proposal to reduce the amount of information MBR sellers are required to provide the commission to prove they lack market power (RM16-3). (See Less is More? FERC Proposal Would Streamline Market-Based Rate Filings.)

“Today’s NOPR attempts to avoid duplication, minimize compliance burdens, modernize data collections and make information collected through its programs more usable and accessible for the commission and its staff,” FERC said.

The commission held a technical conference on its original connected entity NOPR in December, where stakeholders criticized the proposal as cumbersome and confusing. (See ‘Connected Entity’ Proposal Too Broad, Burdensome, Market Participants Tell FERC.)

At FERC’s open meeting last week, commissioners admitted that they had had concerns about the original proposal and expressed appreciation for stakeholders’ feedback.

“I had written separately … on the connected entities proposal to express some questions and concerns, but I’m very pleased to support the revised proposal before us today,” Commissioner Cheryl LaFleur said.

“Sometimes when the commission puts out a Notice of Proposed Rulemaking, there is a huge body of evidence that we have,” Commissioner Tony Clark said. “Sometimes — and I think this is one of those cases — the commission is putting something out, and we’re always genuinely interested in your feedback, but we’re interested in hearing your feedback on something that probably just isn’t quite as well fleshed out.”

FERC also proposed a database using an extensible markup language (XML) schema to keep track of entities’ relationships. The NOPR contains a draft data dictionary that lays out how to submit the required information.

The commission said it plans a “substantial outreach” effort to get input on the NOPR. As a first step, it announced it would convene a technical conference Aug. 11 to discuss the data dictionary. Comments on the proposal are due 45 days from its publication in the Federal Register.

July 25, 2016

FERC: MISO, SPP Need Refund Requirements for Nonpublic Utilities

By Suzanne Herel and Rich Heidorn Jr.

FERC last week ordered Section 206 proceedings in MISO and SPP, questioning the RTOs’ failure to require nonpublic transmission owners to provide refunds in the manner it requires of public utility owners.

The commission expressed “concern that the refund commitments provided by the nonpublic utility transmission owners thus far do not apply to the full range of situations in which they may receive revenues associated with service provided due to their status as transmission-owning RTO members based on RTO rates, terms or conditions that are found to be unjust and unreasonable,” it said in the MISO order, which resulted from a complaint brought against the RTO by a group of transmission owners (EL15-45, EL16-99).

The commission raised similar concerns in opening the 206 proceeding for SPP, saying the lack of full refund provisions for non-public utilities could result in cost shifts, meaning “SPP’s resulting jurisdictional rates may not be just and reasonable” (EL16-91).

Although the commission cannot directly order refunds from nonpublic utility transmission owners that have joined RTOs, FERC said SPP and MISO could compel such refunds indirectly. It suggested the RTOs revise their Tariffs to require non-jurisdictional TOs to promise to honor refunds ordered in FPA Section 205 and 206 proceedings. Such refunds would include those correcting errors in the application of their formula rates and costs later found to be unjust and unreasonable.

“If a nonpublic utility transmission owner chooses not to make such a refund commitment, then SPP would remove its transmission revenue requirement(s) from the SPP Tariff as of a prospective date to be determined by the commission,” FERC said.

In the MISO ruling, FERC also denied the MISO Transmission Owners’ request for rehearing regarding whether a public utility’s ROE may be found unjust and unreasonable even if it falls within the “zone of reasonableness.” FERC set that zone at 7.03 to 11.74% in a June 2014 ruling involving New England TOs.

The commission cited precedents showing that an ROE may be both within the zone and unjust and unreasonable. (See Rural Utilities Allowed to Continue ROE Fight.)

The commission also granted in part and denied in part rehearing requests in a separate docket involving a dispute over base ROEs. (See MISO TOs Seek Base ROE of 11.39%.) The commission denied a request for rehearing from the MISO TOs and Xcel Energy regarding the effective refund date FERC had set. It did grant in part Xcel’s request for rehearing with respect to refunds for nonpublic utility transmission owners.

In EL14-12-001, FERC agreed to clarify its Oct. 16, 2014, order that set hearing and settlement judge procedures along with a refund effective date related to the base ROE for MISO transmission owners. (See ROE Talks Between MISO Industrials and TOs Collapse.)

July 21, 2016

FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard

By Michael Brooks

WASHINGTON — FERC directed NERC on Thursday to develop a “forward-looking, objective-based” critical infrastructure protection (CIP) reliability standard for supply chain management, one that would place the onus on utilities to develop their own plans for protecting the production and distribution of industrial control system hardware and software (RM15-14-002).

Commissioner Cheryl LaFleur dissented in the 3-1 decision.

The commission’s order requires each affected entity’s plan to address four objectives: software integrity and authenticity; vendor remote access; information system planning; and vendor risk management and procurement controls.

FERC emphasized the flexibility it provided NERC in developing the standard. “There is no requirement for any specific controls, nor does FERC require any ‘one-size-fits-all’ requirements,” it said. “The new or modified reliability standard should instead require responsible entities to develop a plan to meet the four objectives while providing flexibility to responsible entities as to how to meet those objectives.”

“The draft final rule directs ‘what’ gap NERC should address,” the Office of the General Counsel’s Kevin Ryan told the commission at its open meeting, “not ‘how’ NERC addresses that gap.”

“I’m happy to support today’s order because I do think it reaches the appropriate balance of pairing together an appropriate sense of urgency on the issue with a prudent flexibility that’s going to be needed by NERC to develop the rule,” Commissioner Tony Clark said.

This is only the third time that FERC has directed NERC to develop a reliability standard; usually, NERC proposes new or revised standards, and FERC issues Notices of Proposed Rulemaking (NOPRs) to adopt them. The commission previously ordered NERC to develop standards on geomagnetic disturbances and physical security.

Clark drew a comparison to the physical security standard in his support for the order. “With the physical security standard, we weren’t telling NERC to tell fence builders how to build their fences, which would be beyond our authority, but rather to come up with a standard so that utilities can incorporate those best practices to ensure physical security of the grid.”

LaFleur Issues Lengthy Dissent

It was this flexibility that led Commissioner Cheryl LaFleur to vote against the order. “I recognize that today’s order on the face appears to afford a great deal of flexibility, but I believe that flexibility is in fact a lack of guidance on the issue we’re addressing,” she said at the open meeting.

LaFleur argued that the rule should have been issued as a NOPR instead to allow more input from stakeholders.

FERC first issued a NOPR addressing cybersecurity, including supply chain management, almost exactly a year ago. While the commission approved seven NERC-proposed standards in the NOPR in January, it held off on addressing the supply chain, holding a technical conference later that month. (See FERC Postpones Action on Supply Chain Protections.)

FERC on Thursday also denied a request for rehearing of its approval of the seven standards (RM15-14-001).

Commissioner Colette Honorable noted that FERC received comments from 34 parties on the NOPR and 24 additional post-technical conference comments. “I think our work in this particular effort demonstrates that we did heed the concerns raised by industry, government, vendors, folks in academia and others,” she said.

“It is worth noting,” LaFleur wrote in a four-page dissent, “that the four objectives that will define the scope and content of the standard were not identified in the supply chain NOPR. Therefore, even though the final rule reflects feedback received on the supply chain NOPR, and is not obviously inconsistent with the supply chain NOPR, no party has yet had an opportunity to comment on those objectives or consider how they could be translated into an effective and enforceable standard.”

And in a rare — albeit low-key and brief — debate at an open meeting, LaFleur rebutted Clark’s comparison of the new rule to the physical security standard. Clark said the latter standard had a quicker turnaround than FERC had required, while there has been “significantly more comment … and process leading up to this particular order.”

“Although the timeline was short, I thought that was actually an example of very focused outreach in advance,” LaFleur said. “We actually ordered the Office of Electric Reliability to work with NERC on the structure of the standard before we issued the directive and [to] agree in advance on a timeline. And as a result, I think we issued — even though we didn’t say ‘build a fence’ — a pretty focused standard, and they complied pretty quickly.

“But of course reasonable minds can differ.”

The rule will take effect 60 days after its publication in the Federal Register. NERC will then have a year to submit the standard.

Further Cybersecurity Measures

FERC also issued a Notice of Inquiry on Thursday seeking comment on potentially revising CIP standards to address separating the Internet and industrial control systems in transmission control centers (RM16-18).

The notice is in response to last year’s cyberattack in Ukraine, in which hackers, likely from the Russian government, infected three Ukrainian utilities with the BlackEnergy virus. Workers at the utilities downloaded seemingly innocent Microsoft Office files that had been emailed to them and enabled macros that allowed the hackers to gain control of the companies’ cyber systems, eventually knocking out power to 225,000 customers in the country. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

In its report on the incident, the Department of Homeland Security recommended, among other measures, isolating industrial control systems from the Internet and other unsecured networks at control centers. FERC seeks comment on any potential impacts on the grid from doing this.

July 21, 2016January 23, 2024

Revised Western RTO Governance Plan Highlights State Authority

By Robert Mullin

CAISO has released a revised set of principles for governing a Western RTO in a bid to convince skeptics that an expanded ISO will be amenable to the entire region. The new document won initial praise, although doubts remain.

The ISO’s governance changes seek to address the concerns of industry participants in the broader West who contend that the original proposal favored California interests and didn’t sufficiently protect individual states’ authority over electricity-related matters. (See CAISO Governance Plan Fails to Dispel Western Concerns.)

“I will say that the revised proposal appears to be a step towards us rather than a step away,” said Bryce Freeman, administrator of the Wyoming Office of Consumer Advocate, noting that he hadn’t yet studied the proposal in depth.

“The question is, is it enough to keep the [PacifiCorp] states engaged?” said Freeman, who criticized the original proposal as being “California-centric.”

State Approvals Needed

That engagement will be essential for CAISO’s expansion into areas of the West now served by PacifiCorp. A widely accepted governance structure is key to the Portland-based utility gaining regulators’ approval to join the ISO in 2019. Regulators from five states outside California — Idaho, Oregon, Utah, Washington and Wyoming — must sign off on membership.

“We think the revised proposal marks a positive step in the right direction and that the changes appropriately reflect input from stakeholders, including on the key issue of striking the right balance between the existing authority of the ISO’s board and California and the other affected states,” PacifiCorp spokesman Bob Gravely said.

The updated proposal attempts to strike that balance in part by scrapping a controversial plan to appoint an “initial” RTO board of governors on which California-appointed members would have held a 5-4 majority. That board was slated to remain throughout a transition period and would have selected the “final” board based on a process developed by a transitional committee. Freeman previously referred to the initial board as the “mother of all California-centric concerns.”

Transitional Committee

CAISO is now proposing that the transitional committee develop a nominating and approval process to select a new nine-member board. The new board would be selected within 18 months of the effective date for the governance plan, which the transitional committee would develop and submit to the current board for approval.

New board members would fill seats created under the governance plan, as well as the open seats of sitting board members as their terms expire. Transitional committee members could extend the terms of sitting board members after determining that doing so would be beneficial to the new board based on “expertise and institutional knowledge.”

The revised proposal also fleshes out the composition of the transitional committee.

“The details are drawn from the Energy Imbalance Market transitional committee, which was successful in developing a governance structure that gave the entire region a voice in the market rules for the EIM,” CAISO said.

Each state in the expanded RTO footprint would be entitled to appoint a committee representative through its own process. In addition, stakeholders throughout the region would select representatives to the committee from nine sectors: investor-owned utilities; publicly owned utilities; independent power producers; large-scale renewable energy providers; distributed energy resource providers; generators and marketers; federal power marketing administrations (PMAs); public interest groups; and state-sanctioned ratepayer advocates.

In addition to developing the governance plan, the transitional committee would be responsible for dealing with other issues, such as whether to create a funding mechanism to facilitate participation in the RTO by consumer advocates.

CAISO’s modified proposal clarifies the role and powers of the Western States Committee (WSC), previously referred to as the body of state regulators. A representative from each RTO state would be appointed to the WSC, which also reserves one non-voting slot each for PMAs and publicly owned utilities. State committee members are not required to be regulators.

The WSC would “provide input on matters of collective state interest” and hold “primary authority” over certain RTO policy initiatives related to transmission cost allocation and resource adequacy.

“Primary authority means the committee will play the lead role for its defined areas of authority, and policy approval by the committee would be a prerequisite to any Section 205 filing with FERC in those areas,” CAISO said.

Still, the ISO would reserve the right to file with FERC without WSC approval “when reliability is imminently threatened.”

‘Genuine’ Effort

The proposed principles make an explicit concession to state sovereignty, promising that governing documents would include “binding provisions” to “protect and preserve state authority over matters regulated by the states themselves,” including procurement, resource planning, retail rates, and resource and transmission siting.

“The proposal appears to genuinely making an effort to preserve state sovereignty,” said Michele Beck, director of the Utah Office of Consumer Services. “But there’s a limit to what you can do in any proposal.”

Beck cited the U.S. Supreme Court’s April decision in Hughes v. Talen Energy — which struck down a Maryland program to incentivize in-state generation — as an example of how participation in an RTO can compromise a state’s authority. (See Supreme Court Rejects MD Subsidy for CPV Plant.)

“Ultimately, policymakers will have to weigh whether a certain amount of loss of sovereignty is worth the benefit,” Beck said.

While Beck was encouraged that CAISO set aside a position for consumer advocates on the transitional committee, she was also wary of a process modeled on the EIM, which she said left out the perspective of consumer groups.

Show Me the Benefits

She also thinks Western industry participants need to be looking beyond the governance issue.

“I want to remind people that governance is a big concern, but we still have to see benefits,” Beck said, pointing out that no studies have been performed to assess how consumers in individual states will be affected by PacifiCorp joining an RTO.

The utility says such a study is in the works.

“Having a final governance structure approved by the legislature that can be supported by other states, as well as completing a full cost analysis to determine net customer benefits, remain the two most important steps that will determine if we continue to move forward,” said PacifiCorp’s Gravely.

CAISO will take up discussion of the revised proposal during a public forum held in Sacramento on July 26. After taking a last round of comments, the ISO plans to send a final governance proposal to Gov. Jerry Brown, who is expected to present the plan to the state legislature in August. Lawmakers must approve any changes to the ISO’s governance structure.