Page 1413 – RTO Insider

July 25, 2016

MISO Planning Advisory Committee Briefs

MISO has settled on a probability weighting for the futures analysis in its 2017 Transmission Expansion Plan, with existing trends given 31% consideration, policy regulations given 43% and accelerated alternative technologies receiving 26%.

The RTO relied on stakeholder feedback to tweak the weighting and used an average of weighting that each sector recommended. MISO had originally proposed using a 30% weighting for existing trends, 40% for policy regulations and 30% for accelerated alternative technologies. (See “MTEP 17 Futures Process Enters Stakeholder Inspection,” MISO Planning Advisory Committee Briefs.)

MISO’s J.T. Smith said stakeholder feedback played a major role in developing the final weightings, and stakeholders said the process has gone well.

The RTO also released its refinements to the MTEP 17 futures siting methodology, vowing to represent zonal resource adequacy requirements and solar and expanded wind zones and develop distributed generation siting methodology. It will consider National Ambient Air Quality Standards nonattainment areas in the siting process.

miso planning advisory committee — MISO’s Tiers 1-3 would allow the RTO to add 50 GW of wind beyond that already enabled by multi-value transmission projects. Tier 4 would allow for an additional 30 GW. *Map Source: MISO*

MISO will share final MTEP 17 capacity forecasts and siting locations at the September Planning Advisory Committee meeting and is urging participants to submit comments in early August.

With a number of plant shutdowns looming in the next five to 15 years, MISO is also looking to improve its generation retirement sensitivities beginning with MTEP 17. The RTO is proposing to consider age-based retirements of coal, oil and gas units in the five-year MTEP reliability assessment. The study will identify necessary projects that will require lead times of more than five years and low-cost upgrades that can be implemented in advance of retirements, said Neil Shah, a seams administration adviser at MISO. The analysis would assume a lifespan of 65 years for coal plants and 55 years for oil- and gas-fired facilities, but would not assume any for nuclear stations.

The proposal received substantial inquiry and criticism from participants, who said it could be redundant and presumptuous. Among the concerns were questions about whether this planning was addressed in existing protocols and how MISO chose specific parameters, such as the plant lifespans. The plan also doesn’t currently address non-transmission alternatives to avoid engaging system support resources.

MISO contends the study could eliminate the need for an SSR agreement for most generation retirements. Staff is requesting stakeholder input on the study enhancements by Aug. 3.

The RTO is also requesting that feedback on the MTEP 17 scope be submitted by September. A summary of the feedback will be presented at the October Planning Advisory Committee meeting and the project’s scope will be adjusted by the end of the year. Beyond core studies to maintain reliability of the system, which are required by FERC and NERC, the MTEP includes targeted studies to optimize market efficiency. Participants may make requests for the targets of those studies; however, not all of them may be able to be accommodated. All feedback should be sent to Adam Solomon.

Meanwhile, a first draft of MTEP 16 is set to be released for external review by MISO on Aug. 8, with stakeholder review and comments expected to roll in by Aug. 22. The draft has been circulating within MISO since July 22. A second draft is slated for release on Sept. 19, with PAC review on Sept. 28 and a vote on Oct. 19. The timeline is aimed for approval at the Dec. 8 Board of Directors meeting.

As of the second quarter of this year, MISO reports there are 633 active MTEP projects totaling $11.1 billion. Another 130 projects valued at $1.9 billion are under construction, while 11 MTEP-approved projects, at $200 million, have been withdrawn. By the end of 2016, MISO expects another $2.5 billion worth of projects to be operational.

Duff-Coleman Selection Moves into the Evaluation Phase

MISO staff is conducting a tariff-required completeness check of developer proposals for the Duff-Coleman transmission project, the RTO’s first Order 1000 competitive solicitation. The identities of the bidders will be released by Aug. 19. Project selection is expected by Dec. 30.

Competitive Transmission Protocol Modifications

MISO is requesting feedback on proposed modifications to Business Practices Manual 20 and 27 and a draft joint functional control agreement.

The BPM 20 modifications would adjust status reporting requirements for market-efficiency and multi-value projects and create variance analysis requirements. MISO Transmission Owners and Wisconsin Electric submitted comments during a previous request for feedback. The BPM 27 modifications would change timing and deadlines for various steps in the RFP process.

The agreement ensures that MISO retains functional control of transmission infrastructure if a portion of the transmission owners decide to leave MISO. All comments or questions are requested by Aug. 3 and should be sent to TDQS@misoenergy.org.

Merchant HVDC Task Team Proposed

The Interconnection Process Task Force is proposing the development of a task team to develop HVDC interconnection procedures. The Merchant HVDC Task Team would meet at least monthly from August through December and report on its activities at PAC meetings.

MISO Tries to Please FERC with Second Attempt at Queue Reform

In another bid to win FERC approval for its interconnection queue reform, MISO plans to cut an initial milestone payment by $1,000/MW of new capacity and assess subsequent milestone payments based on a percentage of upgrade costs.

The revised M2 milestone would become a flat charge of $4,000/MW of new capacity instead of the proposed $5,000/MW. The M3 and M4 milestones will be redefined as 10% and 20% of upgrade cost, respectively.

MISO said it will define the upgrade cost the same way it does in the initial payment section of its generation interconnection agreement, which includes network upgrades, distribution/generator upgrades and TOs’ interconnection facilities and system protection facilities.

MISO said the revised milestone payments will be applied toward the GIA initial payment. It also said it will settle any over- or underpayment after it completes a final facility study.

The RTO plans on posting Tariff redline changes for stakeholder review on July 29 and wants to file the revised queue process at the end of October for a Jan. 1 effective date.

If the new batch of adjustments is accepted by FERC, MISO plans on transitioning completely to the new queue beginning with projects that enter next August.

In March, FERC rejected MISO’s proposed changes, calling the revised milestone payments a barrier to entry and rebuffing the RTO’s explanation that the current project backlog was due to “speculative” projects. (See MISO Queue Changes on Hold Pending Technical Conference.)

So far in 2016, MISO has received 105 new queue requests representing a possible 16.9 GW, and the RTO reports that 12 projects worth 1.9 GW have newly signed interconnection agreements.

MISO is also proposing to move two study deadlines four months ahead under Business Practices Manual 15, which governs generator interconnection. Under the changes, MISO’s annual interim deliverability and energy resource interconnection service studies would be completed by Oct. 31 instead of the current June 15.

“We did not meet [the current deadline] this year, and we did not meet it last year,” said Tim Aliff, MISO’s director of resource interconnection and planning.

— Amanda Durish Cook & Rory D. Sweeney

July 25, 2016

Electric Industry Lobbies, Waits on CFTC Private Rights Ruling

By Tom Kleckner

RAPID CITY, S.D. — The electric industry has done its part in building opposition to the U.S. Commodity Futures Trading Commission’s proposal to allow private rights of action on energy market transactions, which would make RTOs and their market participants potential targets for lawsuits outside the FERC process.

It flooded CFTC with comments against the proposal. It worked with the Senate Appropriations Committee to file legislative language ensuring the current regulatory framework remains in place. (See Congress May Order CFTC to Back Down on Private Rights.)

And now it waits.

“I believe we as an industry have done everything we can do, through the legislative process and FERC and comments,” Mike Ross, SPP’s senior vice president of governmental affairs and public relations, told the Strategic Planning Committee on July 14. “When the ruling is, we don’t know. August, September, October, we don’t know. It could be today.

“My sense is they won’t leave us hanging too long — but this is Washington.”

electric industry, cftc — Ross *© RTO Insider*

Ross, a former six-term Democratic representative from Arkansas’ 4th Congressional District, said the committee’s bill could be in the expected year-end omnibus bill, which he said would solve the RTOs’ problem. In the meantime, all he and others in the industry can do is try and discern where the three CFTC commissioners stand.

“We know Commissioner [J. Christopher] Giancarlo is with us,” Ross said, citing his “substantial” comments. Chairman Timothy G. Massad has been pushing the commission’s proposal, but Commissioner Sharon Y. Bowen, who voted with Massad on a draft order including the private rights of action, has been “pretty silent,” Ross said.

“It only takes two of the three,” he reminded the committee.

The issue arose when the Dodd–Frank Wall Street Reform and Consumer Protection Act, which Ross voted against, was passed in 2010. The bill revised the Commodity Exchange Act (CEA) and provided CFTC with authority to exempt RTO markets from its rules.

Six of the seven RTOs filed for exemptions, which CFTC granted in 2013. SPP filed for a “me-too” exemption in 2013, as it began to go live with its day-ahead market. The commission issued a draft order on the SPP request in May 2015, which included preamble language that said CFTC never intended to exempt other RTOs from private rights of action.

Ross said the commission notified SPP in March that it was delaying a decision on the order and opening a new docket (81 FR 30245) to consider removing the exemption for all RTOs.

“They said, ‘We’re going to put y’all’s me-too on the shelf and we’re revisiting the [exemption] for other RTOs. Whatever we do for them, we’ll do for you too,’” Ross said in recounting the conversation. “That’s when the electric industry became very engaged in the issue.”

Ross helped facilitate supportive comments made by the House of Representatives’ Committees on Energy and Commerce and Agriculture, FERC and several industry groups. A total of 43 comments were submitted, with 38 in favor — 15 by SPP members — and five opposed.

The FERC comments, provided by General Counsel Max Minzner, said “introducing a private right of action to these markets via the CEA appears inconsistent with Congressional intent and would conflict with the design” of the Federal Power Act.

“Those are pretty strong words coming from FERC to the CFTC,” Ross said. He said the comments were not unprecedented, but it is “unusual for an agency to file comments in another agency’s” docket.

The ISO/RTO Council called CFTC’s proposed amendment “unnecessary.” It said FERC and the Public Utility Commission of Texas, which regulates ERCOT, “have the necessary tools, resources and experience to maintain the integrity of ISO/RTO markets.

“The CFTC proposal would permit market participants suffering a loss in a transaction to sue an ISO or other market participants if it believed the loss arose from the gaming of rules,” the IRC said. “Permitting private action would undermine confidence in market transactions by both market participants and state electricity regulators, which would ultimately degrade consumer protections that the current oversight process affords.”

As it stands now, Ross warned the SPC, private rights of action could allow any lawyer in any RTO region to file a lawsuit with any of the more than 100 U.S. district courts, which may not have a full understanding of what constitutes a swap in energy markets.

“FERC understands this,” he said. “They make a decision, and if you don’t like the decision, then you go to court.”

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.)