Page 1344 – RTO Insider

March 6, 2017

Western Stakeholders Support Continuing EIM Regional Forum

By Robert Mullin

LAS VEGAS — The West-wide forum created by CAISO to foster discussion about Energy Imbalance Market-related issues outside the ISO’s normal stakeholder process is worth preserving — and developing further.

EIM regional issues forum — Schmidt | © *RTO Insider*

That was the general consensus of stakeholders and EIM Governing Body members who gathered at The Palazzo hotel last week to discuss the fate of the Regional Issues Forum (RIF), which was established in 2015 as the ISO began to build momentum for “regionalization” — the push to expand into other parts of the West.

“We all value what the RIF has been doing,” Governing Body Chair Christine Schmidt said during a Feb. 28 joint meeting that included fellow body members, RIF representatives, industry participants and interest groups. “We value the promise of what the RIF can do going forward.”

‘Learning a Lot’

Speaking in her capacity as a Washington state utility commissioner, Ann Rendahl — chair of the EIM’s Body of State Regulators — voiced her support for the RIF as someone “who is coming into this market new and learning a lot.”

“The Regional Issues Forum discussions have been very helpful, because you are all participating in the market and you have experiences that are helpful for us to learn and hear, in addition to the formal stakeholder processes that the ISO puts on,” Rendahl said.

Accolades notwithstanding, uncertainty still looms about the future role for the forum, what formal structure it should assume and how it should interact with the Governing Body.

Doug Howe, the body’s vice chair, referred to it as “the existential question of ‘What’s the RIF?’”

RIF representatives, called “sector liaisons,” have committed to answering that question and developing an operating framework for the group in time for the Governing Body’s July meeting.

“The liaisons don’t see a lot of barriers to getting this done in an expedited way,” said Tony Braun, RIF chair and a liaison representing the publicly owned utilities sector.

Informal Body

The RIF was conceived under the EIM charter as an informal body to enable industry stakeholders and the public to discuss wide-ranging issues related to the West’s only real-time energy market. (See PacifiCorp Offers Lessons for Future EIM Participants.)

The forum is organized by 10 liaisons representing five industry sectors: independent power producers and power marketers; transmission-owning utilities; publicly owned utilities; consumer advocates; and balancing areas neighboring the EIM — the last of which is a diminishing group as the EIM grows, Braun joked. CAISO planned for the RIF to meet about three times a year but required no set schedule.

According to the ISO, “The forum may produce documents or opinions for the benefit of the EIM Governing Body, ISO Board of Governors and the ISO,” but it sits firmly outside established stakeholder processes.

The EIM’s governance documents call for the RIF’s role to be re-evaluated by next month, which was the primary reason for the Feb. 28 joint meeting.

Re-evaluation Process

A key question in the re-evaluation: How should the RIF run the process to re-evaluate itself?

“Should this be an ISO-run stakeholder process in the traditional fashion?” asked Braun. “Is this something that the liaisons should take ownership of? What should be the liaisons’ role in putting together the recommendations and things like that, if any?”

Schmidt said she didn’t think the RIF’s evaluation was ever intended to become part of an ISO stakeholder process.

“I think the general consensus [among CAISO and EIM leaders] is that the Regional Issues Forum is the Regional Issues Forum,” Schmidt said. “However the re-evaluation needs to take place, this is in your control and is in your span of control and authority, and you should actually go through that process as a Regional Issues Forum issue.”

Speaking on behalf of her company, RIF liaison Sara Edmonds, general counsel at PacifiCorp Transmission, supported the general independence of the RIF, but she noted that the group has no funds or processes to post material coming out of its meetings.

“We’re happy as the liaisons to kind of be the muscle to pull together the substance [of the re-evaluation], but we’re still going to need the ISO vehicle to get the information out [and] help us with the meetings,” Edmonds said.

Ellen Wolfe of Resero Consulting, representing the Western Power Trading Forum (WPTF), backed Edmonds’ view. The WPTF sees “a lot of value” in the continuation of the RIF and agrees with the bottom-up approach to re-evaluation, she said.

‘Grass-Rootsy’

“We do like the idea of the RIF being very ‘grass-rootsy,’ so to speak, but also appreciate the ISO providing the infrastructure for posting comments and market notices and so forth,” Wolfe said.

Howe sought more clarity on the process the RIF would adopt in its re-evaluation.

“So we know that is not going to be a formal ISO stakeholder process — which means a few things, but among them is that you’re not going to start with an issue paper that’s going to be delivered to you by the staff of the ISO,” Howe said.

“So, to some extent, either you’re going to have to deliver the issue paper, or you’re going to have to take in the comments, perhaps write a strawman proposal, and send that out for another round of comments.”

Howe wondered whether ISO staff would ultimately be charged with writing the strawman based on what RIF liaisons heard during the Feb. 28 meeting.

“In my mind, we’re either fish or fowl,” Braun responded. “So if this is a process that the RIF liaisons are going to take ownership of, then my colleagues as the liaisons need to pick up the pens and craft the issue paper of the first straw proposal.”

“We’re all devoting our time and energy to this because we think it’s important,” said RIF liaison Matt Lecar, principal at Pacific Gas and Electric. “But there is a lack of formal structure, and therefore a lack of funding and resources to do things like write the extensive issue papers and straw proposals that the CAISO staff otherwise would in a CAISO stakeholder process.”

Hands Off

On the question of who should be responsible for approving the RIF’s proposal for a framework, Governing Body members advocated a mostly hands-off position.

“I am not seeking to have authority over what the RIF does,” said Governing Body member Valerie Fong, adding that she wouldn’t want to be cut out of the RIF’s activities because of the forum’s educational value. “I won’t be offended if [RIF members] decide that the EIM Governing Body does not have a decision in this process.”

Howe seconded Fong’s sentiments, saying he didn’t see a role for the Governing Body to put its “blessing” on the RIF’s final proposal.

“The primary purpose of this [process] is to construct an organization that helps you all to be effective, and I just want to thank you for including us in that,” Governing Body member Carl Linvill said. “But as far as any kind of formal approval, I’m with what everybody else has said: I don’t think we need that.”

Fellow body member John Prescott said it was important for the RIF to be transparent.

“What I want is access to the knowledge,” Prescott said.

Schmidt reminded her fellow body members that the RIF is embedded in the EIM’s governing documents, meaning that decisions around the RIF will still be subject to some CAISO oversight.

“If there’s a resource impact, or any other impact on the ISO or the ISO’s Tariff, those are matters that will have to be decided by the EIM’s Governing Body and ultimately the [ISO’s] Board of Governors,” Schmidt said.

RIF as Author?

Another key issue facing the RIF: whether it will produce papers on issues coming before the EIM Governing Body.

Stacey Crowley, Roger Collanton, Valerie Fong, Doug Howe, Christine Schmidt, Carl Linvill, John Prescott | © *RTO Insider*

On that subject, Braun said stakeholder comments ranged from “no, that’s not what the RIF is for” to “yes.”

Howe said the question must be preceded by what issues the RIF will undertake.

“Are you going to take on issues in the stakeholder process?” Howe asked. He added that the RIF will “need to decide how you’re going to decide.”

Fong noted that operating guidelines are “somewhat silent” on a lot of RIF issues.

“If I were you, I would keep my options open,” she said.

‘Happy to Help’

Lecar wondered if there would be resources available to the RIF to take on larger written work projects.

Stacey Crowley, CAISO vice president for regional and federal affairs, affirmed that ISO staff would be willing to take down comments from a RIF meeting.

“We’re happy to help,” Crowley said, adding that it would be up to the RIF, however, to craft substantive policy recommendations.

Howe emphasized the need for the RIF to document the views arising within its discussions. “If you don’t turn this into a written product, these are conversations that get lost in the dark,” he said.

Jennifer Gardner, staff attorney with Western Resource Advocates, asked whether the RIF could play the role of flagging issues for the Governing Body that are not already being addressed in CAISO’s stakeholder process.

“Is there value, from the Governing Body’s perspective, in having something a little bit more formalized with the RIF?” Gardner asked. A more formal process would entail producing written comments, rather than just “casual dialogue” among RIF participants.

“Does the RIF have to come to consensus on everything?” Fong asked. “Does it have to be giving us an overall perspective from a RIF level? I’d say ‘no.’ I’m OK with the individual input” from RIF participants.

Howe agreed with his colleague and added his own perspective.

“For me, the value is the eyes and ears out in the field to flag issues which may not have risen to the level [of] the ISO yet,” Howe said. “What doesn’t have value for me would be for the RIF to try to turn itself into a formal stakeholder process, because we’ve already got that [within the ISO]. And that just wouldn’t provide additional value.”

March 3, 2017

PJM Sticks with LS Power on Artificial Island Project

By Rory D. Sweeney

VALLEY FORGE, Pa. — And the winner is … LS Power, again.

Warren Beatty wasn’t on hand, but PJM still received plenty of criticism Friday after planners reaffirmed — with some scoping changes — their previous selection of LS Power’s proposal for the contentious and long-awaited reliability upgrades on Artificial Island.

The island on the southwestern edge of New Jersey is home to three nuclear reactors owned by Public Service Enterprise Group, which have been forced to operate for years below capacity and in accordance with a complex operating guide.

pjm ls power artificial island — Salem and Hope Creek Nuclear Generating Stations on Artificial Island

Last August, PJM’s Board of Managers suspended the project for additional review after PSEG raised a series of engineering concerns and increased the cost estimate for its portion of the upgrades by at least $135 million. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)

Scope, Costs Reduced

At Friday’s special session of the Transmission Expansion Advisory Committee, PJM officials said their review confirmed that LS Power’s proposal for a 230-kV line from Artificial Island to a new Silver Run substation in Delaware was the best solution but that the interconnection point should be changed from the Salem plant to Hope Creek. The analysis also determined that a static VAR compensator (SVC) at the New Freedom substation and optical groundwire upgrades provided little benefit and were unnecessary.

The planners’ recommendations will be forwarded to the board for final approval.

In addition to eliminating those upgrades from the scope of work, planners recommended implementing a voltage schedule at the plants and revising the in-service date to June 1, 2020.

Much of the discussion on Friday focused on the project’s costs compared to those of the other finalist, a project proposed by PSEG subsidiary Public Service Electric and Gas that would follow an existing transmission route north through New Jersey.

PJM’s analysis found that LS Power’s project would cost $265 million, $11 million more than PSE&G’s. But planners said LS Power’s proposal, which contained hard cost caps, provided “greater cost certainty.” PJM’s Paul McGlynn, who oversees the project’s development, said PSE&G’s project also raised permitting concerns because it would run through the Supawna Meadows National Wildlife Refuge.

pjm artificial island ls power — PJM planners reaffirmed their 2015 selection of LS Power’s 230-kV circuit line to Delaware as the fix for stability problems at Artificial Island in New Jersey. Planners, however, determined that the line should connect Artificial Island at the Hope Creek nuclear generator rather than the nearby Salem plant. | *PJM*

As approved in July 2015, the project was expected to cost $270 million to $283 million. The February 2016 update that prompted the suspension pushed the cost to $418 million with the Salem interconnection more than doubling to $152 million from a maximum of $74 million.

Replacing the Salem connection with one at Hope Creek will save $20 million, and eliminating the optical ground wire and SVC trimmed an additional $120 million. That brings the projected cost to $265 million, with a cost cap of $278 million — within the bounds of the original project cost estimates.

PJM also pointed out that LS Power has already spent about $6.5 million on preliminary work, so switching projects would mean writing off that expense as a sunk cost. The RTO acknowledged that PSEG has also spent money on developing work estimates for PJM regarding its project but “didn’t think” to quantify it, said Vice President of Planning Steve Herling.

Stakeholders from PSEG and Dominion were among those criticizing PJM’s new recommendation.

More ‘Granular Review’

PJM said the suspension allowed time to conduct a “more granular review and re-evaluation” of the project, including additional site visits and marine and terrestrial surveying, a review of permits, property rights and scheduling issues and preliminary engineering.

Planners determined the optical groundwire and related line relay changes would not impact the site’s operating guide or improve stability margins because of the timing of the most critical bus fault’s clearing. They said if a need is identified for the upgrades later they would be pursued as a separate project.

The SVC was replaced with a recommend voltage schedule for Salem and Hope Creek requiring operation at a minimum of 527.5 kV, a level PJM said was “maintained in nearly all conditions since 2012.”

PSE&G insisted its proposal was “more robust” than LS Power’s, providing larger stability and system reliability margins and — because it would employ a 500-kV line — more than three times more capacity than its competitor’s 230-kV line.

PSEG’s nuclear division sent the PJM board a letter March 2 warning that it has an option to build another reactor at the Hope Creek station and that the connection at Hope Creek might have to be moved if it moves forward with another reactor. Herling said PJM has no control over that and that future work at the site would need to be reviewed on a “case-by-case” basis.

LS Power’s Sharon Segner said it’s not an “apple-to-apples” comparison because PSEG’s proposal excludes any overruns for environmental permitting and securing real estate rights, while her company’s includes risks for both. In addition, LS Power has already contracted for material portions of its project, so the revised, lower cost estimate of $133 million for its portion reflects some actual contractual numbers.

PSEG’s Jodi Moskowitz said that most of the costs in her company’s proposal are capped.

Old Dominion Electric Cooperative’s Mark Ringhausen said it was “deceiving” to use $265 million for LS Power’s project when that is only the company’s current estimate. The proposal is actually capped at $278 million. LS Power’s estimate assumes PSEG’s work at Hope Creek costs no more than $132 million. However, this portion of the project has no cost cap.

First Order 1000 Project

PJM made the Artificial Island upgrades its first competitive solicitation under the PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)

That wasn’t the end of the controversy, however. Delaware and Maryland officials have complained that most of the cost of the project would be allocated to ratepayers on the Delmarva peninsula despite the region receiving little benefit from the upgrade.

Last April, FERC approved the cost allocation for the project, but in June it said it would consider rehearing requests over whether PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is appropriate for the project (EL15-95, ER15-2563). (See FERC Taking Second Look at Cost Allocation for 2 PJM Projects.)

The commission cannot resolve the dispute until new members are appointed to restore its quorum.

Next Steps

Herling said the board will be educated about all of the cost estimates through comprehensive documentation, and “I guarantee they’ll read all of it.”

The next board meeting is scheduled for April 6, so PJM asked that all stakeholder comments on the recommendation be filed by March 31. Stakeholders expressed concerns that PJM won’t have published its comprehensive whitepaper on the topic by then, so all comments will have to be based on existing documents.

March 3, 2017

SPS, SPP Ask Texas to Rule on Transmission Competition

By Tom Kleckner

Southwestern Public Service and SPP have asked Texas regulators to rule on whether Texas law includes a right of first refusal that overrides FERC Order 1000 (Docket No. 46901).

At issue is who will build a 90-mile, 345-kV line from Potter County to SPS’ Tolk Generating Station in the Texas Panhandle. Without a state ROFR, the project would be open to competitive bidding under Order 1000.

right of first refusal SPP SPS texas — Tolk Generating Station | *Xcel Energy*

SPS and SPP asked the Public Utility Commission of Texas to determine whether the RTO can designate entities other than the incumbent utility to construct and own regionally funded transmission facilities in Texas outside the ERCOT service area.

SPS contends in the Feb. 28 filing that the Public Utility Regulatory Act (PURA) allows it, as the incumbent utility operating outside ERCOT, the ROFR to build in the service area prescribed by the PUC. That would prevent a potential competitive project under Order 1000.

SPP says there is “no clear statement in Texas laws” that incumbent utilities have such a right, and it is following the Tariff’s competitive bidding process until the commission “can resolve the issue as a matter of law.”

The ruling will determine who gets to build the Potter-Tolk line — the only one of 14 projects in the Integrated Transmission Planning 10-Year Assessment not approved by SPP’s Board of Directors and Members Committee in January. The board requested the project undergo further study and be brought back to its April meeting. (See “Board Sends $144M Tx Project Back for Re-evaluation,” SPP Board of Directors/Members Committee Briefs.)

SPS filed a lawsuit in a Texas state district court Jan. 18 seeking approval of its right to build the project and other 345-kV projects in its Texas service area. The utility also sought an injunction prohibiting SPP from issuing a notification-to-construct for the Potter-Tolk line to any company other than SPS.

However, the utility and SPP both agreed to temporarily suspend the lawsuit Feb. 27 and file with the PUC instead.

SPS spokesman Wes Reeves said the lawsuit against SPP and the subsequent PUC filing “are not … adversarial in nature.”

“We simply seek clarity on our first right as a non-ERCOT utility to construct and operate regionally funded transmission lines within our service area,” Reeves said.

In a statement, SPP General Counsel Paul Suskie said the two entities agree Texas law is unclear on ROFR issues.

“Our joint filing has been made with the intention of addressing that uncertainty,” Suskie said.

In Order 1000, FERC explicitly acknowledged that it could not override state ROFRs. SPS contends PURA’s legislative history confirms “transmission-only utilities are not permitted outside of ERCOT,” and that any holder of a certificate of convenience and necessity must “serve every consumer in the utility’s certificated area” and “provide continuous and adequate service in that area.”

SPP asserted that because no local Texas laws or statues would be violated by its competitive bidding process, it would treat the Potter-Tolk line as a competitive upgrade and would seek bids for the project.

The parties proposed an intervention deadline of 30 days following the petition’s publication in the Texas Register, set for March 17. Given the proposed schedule, it’s all but certain there will be no resolution before SPP’s April board meeting.

An administrative law judge gave the PUC until March 16 to file comments or make a recommendation. The PUC’s next scheduled meeting is March 9.

March 3, 2017

UTC Trader Displeased with PJM’s Handling of Uplift Rule Changes

By Rory D. Sweeney

A financial trading firm accused PJM of unfairly discounting the interests of up-to-congestion traders in recent rule changes that it says would shift hundreds of millions in uplift charges to them from load.

“PJM is required to act as a neutral body without giving priority to one sector over others. XO is concerned that the packages promulgated by PJM and its [Independent Market Monitor] … benefits load while producing great harm to the Other Supplier Sector, including the financial community,” XO Energy President Shawn Sheehan wrote in a Feb. 24 letter to the Board of Managers.

The letter follows a phased set of rule changes that was overwhelmingly endorsed by the Markets and Reliability Committee in January and the Members Committee in February. (See “Work on Uplift Moves Forward Despite NOPR,” PJM Markets and Reliability and Members Committees Briefs.)

Phase 1 includes in the determination of balancing operating reserve credits only the day-ahead revenues from the hours the resource operated in real-time, not all day-ahead revenues. Phase 2 includes UTC transactions in the allocation of day-ahead and balancing operating reserves in the same way as incremental offers and decremental bids. It would also remove the ability for internal bilateral transactions to offset deviation charges.

XO argues in its letter that the changes create a “triple capacity deviation,” although UTCs are intrinsically transmission products that don’t impact capacity. According to XO’s calculations, the changes will shift as much as 79% of the total real-time uplift charges and 25% of day-ahead uplift to UTCs — a total of more than $388.5 million.

The letter argues that PJM actively worked to force the changes through the stakeholder process and didn’t offer XO and its allies due process.

“XO is concerned that equitable, stakeholder-centric initiatives, which do not comport with fundamental market design principles, such as best practices and causation, are taking precedence” to sound market design, the letter reads. “In the past year or more, XO has witnessed an unwarranted negativity from PJM and its staff towards both financial products and the financial trading community. … Financial market participants feel bulldozed by PJM’s perceived priority in advancing its own proposals through the voting process and its favoritism of other [stakeholder] sectors. These actions are strongly affecting market participants’ confidence in PJM’s ‘neutral’ administration of its duties and its operation of a fair and efficient market.”

PJM did not immediately respond to a request for comment.

The complaint is the latest chapter in a long-running battle among PJM stakeholders over the value of financial products such as UTCs and whether they are paying their fair share of costs.

FERC weighed in on the issue in its Jan. 19 Notice of Proposed Rulemaking on uplift and UTCs. (See FERC Proposes More Transparency, Cost Causation on Uplift.)

XO contends that PJM ignored FERC’s direction in its proposed Phase 3 package that would limit UTCs to zones, hubs and aggregates. Such changes “would effectively remove the products’ ability to mitigate local market power and converge nodal congestion,” the company said. “FERC has repeatedly held that convergence of the day-ahead and real-time markets is a key measure of market efficiency.”

March 2, 2017

SMUD Balancing Area Inks Agreement for EIM Membership

By Robert Mullin

The Balancing Area of Northern California (BANC) has signed an agreement with CAISO that puts the Sacramento Municipal Utilities District (SMUD) on track to join the Western Energy Imbalance Market (EIM) in spring 2019.

sacramento municipal utility district, eim — The footprint of the Balancing Authority of Northern California extends north to south from the Oregon border to Modesto, and east to west from Sacramento to the Sierra Nevada range. | *Balancing Area of Northern California*

The implementation agreement comes four months after SMUD entered negotiations to join the West’s only real-time energy market — making it the first publicly owned utility to do so. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)

Another municipal utility, Seattle City Light, announced its interest in joining the market shortly after SMUD’s announcement and has already signed an agreement with the ISO, putting it on schedule to join up at the same time as the California utility. (See Seattle City Light Signs EIM Membership Agreement.)

The latest agreement calls for a “phased” approach for BANC members to join the EIM, with SMUD’s participation representing the first stage, followed by discussions regarding participation for other members, possibly including federal power marketing agency Western Area Power Administration’s Sierra Nevada region.

Regardless of whether WAPA eventually links up with the EIM, BANC members Modesto Irrigation District and the cities of Redding and Roseville are considering doing so. Two other members — the city of Shasta Lake and Trinity Public Utilities District — own no generating resources and would therefore derive no benefit from joining the market, according to Jim Shetler, BANC’s general manager.

The phased implementation hinges on SMUD being accounted for separately from other BANC members, including “having separate interchange as represented by e-tags, a separate area control error calculation, and separate revenue quality metering,” the EIM agreement states.

SMUD already has an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas.

Another term spelled out in the agreement: CAISO acknowledges that as public entities, BANC members want to remain outside the jurisdiction of FERC.

BANC, in turn, accepts that its transmission-owning members will be required to amend their open access transmission tariffs to reflect the fact that the EIM’s operations are subject to FERC oversight.

“We believe the implementation agreement and our partnership with [the] ISO recognizes the unique situation of our public power members,” Shetler said in a statement. “We are pleased to begin the work that will enable our members to participate in the EIM if they choose to do so.”

caiso eim sacramento municipal utility district — Solano Wind Project in the Sacramento Municipal Utility District | *Balancing Authority of Northern California*

Incorporation of other BANC members in the future will require that the agreement be amended, or that a completely new one be executed.

CAISO CEO Steve Berberich said he was pleased with the decision by BANC and SMUD.

“SMUD is one of the premiere community-owned utilities in the country that will benefit from access to low-cost resources from the entire EIM footprint,” Berberich said.

SMUD has cited the benefits of increased renewable integration, potentially reduced reliance on gas-fired generation and lower operational costs as its primary reasons for joining the market — although the first two benefits outweighed the latter in the utility’s decision-making, according to Shetler. A joint study conducted by BANC and the WAPA estimated that SMUD would gain $2.8 million in yearly net benefits from transacting in the market, possibly increasing to $5 million in about five years — a “small number” compared with the utility’s overall portfolio, he said.

Established in 2011, BANC is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. The agency contracts with SMUD to perform day-to-day balancing functions.

March 2, 2017April 11, 2024

Indiana Senate Moves to End Retail Net Metering

By Amanda Durish Cook

The Indiana Senate has approved a controversial bill that would phase out the state’s retail net metering program.

State senators voted 39-9 to approve Senate Bill 309, which gradually lowers the payments residents receive for selling excess energy from their distributed resources back into the grid. The bill now proceeds to the state’s House of Representatives.

Indiana residents currently earn the retail energy rate for their excess electricity, but the bill would reduce that compensation to 25% above the wholesale rate.

The bill originally contained a “buy-all, sell-all” provision that, if passed, meant homeowners would not have been able to use the power generated by their own solar or wind resources. Instead, they would have been required to sell all output to their local utility at wholesale, to be repurchased at retail. That provision was removed from the bill before the full Senate vote.

The bill underwent other amendments, including the addition of a grandfather clause — expiring in 2047 — for existing net metering customers and any residents who have equipment installed before July 1. Residents who sign up for net metering over the next five years would be covered under existing retail rate rules until 2032.

A provision that would altogether eliminate net metering by 2027 was also tossed from the bill.

The proposed law would also allow utilities to discontinue offering net metering in their service areas when net metering generation equals 1% of their peak summer demand load.

In a Feb. 22 opinion in Fort Wayne’s The Journal Gazette, bill author Sen. Brandt Hershman (R) praised the legislation, calling it a “net gain for Hoosiers.” The bill encourages “renewable energy generation while bringing more fairness and market sensibility to the way privately owned solar panels and wind turbines are subsidized by other customers,” he wrote.

Hoosier Energy Power Network Solar Power Plant in Bloomington, In. Inovateus Solar

Hershman said that having electric utilities pay full retail rates for consumer-generated energy is unfair and that the prices are “two to three times the actual value of the energy on the market.” Net metering was established to encourage investments in consumer-owned solar and wind generation when installation costs were higher, he contended, but the generation is now more affordable. He pointed out that the federal government has reduced its incentives for residential renewables.

The bill has found support from Indiana’s major utilities, according to Mark Maassel, president of the Indiana Energy Association, which represents major Indiana electric utilities Duke Energy, American Electric Power’s Indiana Michigan Power, Indianapolis Power and Light, Vectren and Northern Indiana Public Service Co.

“All Indiana’s investor-owned utilities are working together on this,” Maassel said. “The companies are very thankful for Senator Hershman.”

Maassel said the utilities did not have a hand in authoring or revising the bill.

“The bill, where we ended up at, is a positive step and something we would like moved forward,” Maassel said.

But solar and renewable advocates are not happy with the final product, arguing that the bill gives utilities too much control over residential solar and wind.

“Senator Hershman, Indiana’s monopoly utilities and their friends in the legislature who are backing the bill say it was ‘fixed’ with amendments, but that’s not true,” said Wendy Bredhold, an Indiana-based representative of the Sierra Club’s Beyond Coal campaign. “The utilities want to control solar power and take away Hoosiers’ freedom to generate their own.”

Bredhold called the bill a “step backwards” for Indiana and “energy freedom” and said that it “effectively kills homegrown, rooftop solar” in a state “controlled by powerful utility interests.”

The Indiana Distributed Energy Alliance said the bill “will eviscerate net metering and customer-owned solar and small wind in Indiana.”

Sean Gallagher, vice president of state affairs for Solar Energy Industries Association, said the bill’s language fails to account for the full range benefits that residential generation can provide.

“Compensating … local power at average wholesale prices, as SB 309 proposes, significantly undervalues the benefits of producing that power — such as avoiding the need to build new power lines — and ignores the fact that solar power is produced during daytime peak periods when wholesale energy prices are higher,” Gallagher said.

Gallagher has called on Indiana’s legislature to let the Utility Regulatory Commission investigate the costs and benefits of rooftop solar before setting “arbitrary limits or determining compensation that customers would receive in statute.”

March 2, 2017

Great Plains Asks Missouri PSC’s OK on Westar Deal

Great Plains Energy has complied with the Missouri Public Service Commission’s order that it seek commission approval on its proposed acquisition of Westar Energy.

Great Plains, the parent of Kansas City Power and Light, relented on filing the $12.2 billion sale with the regulators in response to the commission’s Feb. 22 ruling on a complaint by the Midwest Energy Consumers Group.

great plains energy missouri westar deal — Westar Transmission | *Westar*

The group cited KCP&L’s 2001 application to reorganize into a holding company (EM-2001-464). The restructuring — which created Great Plains as parent and KCP&L its subsidiary — contained an agreement that Great Plains would not attempt to merge with or acquire a public utility without first seeking commission approval.

The PSC had ordered Great Plains to file by March 4. Great Plains is asking that the commission render a decision before April 24 to keep the expected spring transaction closing date on schedule.

The commission said last year that it should have jurisdiction over the sale, but Great Plains said that the deal didn’t require its approval because Westar is a Kansas company. (See Great Plains Energy, Westar Shareholders OK $12.2B Deal.)

Great Plains had argued that allowing the PSC in on the decision would “improperly expand the commission’s jurisdiction to include the acquisition of non-Missouri regulated utilities by Missouri-based holding companies.”

— Amanda Durish Cook

March 1, 2017

PJM Refunding $41M to Bilked Market Players

PJM has received FERC approval to divide $40.8 million from an enforcement settlement with GDF SUEZ Energy Marketing among market participants who were impacted by the company’s scheme to improperly capture make-whole payments.

FERC’s Office of Enforcement, which reached the settlement with GDF, approved of PJM’s plan to distribute the funds as negative operating reserve charges to any market participants that incurred deviations between the day-ahead and real-time energy markets between May 2011 and September 2013, according to an email from David Budney, the RTO’s manager of market settlements. It noted that the adjustments have been processed and are available in the market settlements reporting system.

ferc gdf suez pjm market manipulation settlement — The Troy Energy gas-fired plant in Luckey, Ohio, is one of the units GDF Suez used to own in PJM.

The funds are part of a nearly $82 million payment by GDF to settle market manipulation charges for offering generation below cost to capture make-whole payments in PJM. Enforcement charged GDF with violating the commission’s Anti-Manipulation Rule for an improper bidding strategy designed to increase its receipt of lost opportunity cost credits (LOCs).

According to the settlement, the Houston-based power marketer offered below-cost bids on some of its 12 natural gas-fired units to clear PJM’s day-ahead market and profit off the LOCs when the units weren’t dispatched in real time. GDF used a probabilistic, risk/reward approach to compare when units were unlikely to be dispatched against the risk of running the units at a loss, the settlement said. (See GDF SUEZ to Pay $82M in PJM Market Manipulation Settlement.)

GDF’s parent company rebranded as ENGIE in 2015 and sold off its U.S. fossil-fuel generation assets in 2016. PJM has since updated its rules to eliminate the loophole of which GDF took advantage.

– Rory D. Sweeney

March 1, 2017

ERCOT Ending Greens Bayou RMR May 29

ERCOT announced it is terminating its reliability-must-run agreement for NRG Texas Power’s Greens Bayou Unit 5 in Houston, effective May 29.

The grid operator said studies using new criteria indicated the unit would not be needed for transmission system reliability after Exelon’s 1,148-MW Colorado Bend II Generating Station in Wharton County, Texas, becomes operational in June.

The new criteria took effect with the passage of Nodal Protocol Revision Request 788 last fall. NPRR 788 requires a potential RMR unit to have “a meaningful impact on the expected transmission overload” to be considered for an agreement.

ERCOT said the previous rules, which used a forecast based on a 90% probability of exceedance, were overly conservative and that the new criteria should reduce the use of RMR contracts for reliability concerns that have a very low probability of occurring.

The RMR, ERCOT’s first since 2011, was approved last June to run through June 2018. Greens Bayou 5 is the largest of seven units at NRG’s Harris County complex. Built in 1973, the 371-MW natural gas unit was mothballed in 2010 and 2011, but returned afterward. (See “Greens Bayou Still Needed Under RMR Protocol Changes,” ERCOT Board of Directors Briefs.)

– Rich Heidorn Jr.

February 28, 2017

ISO-NE Begins Discussing Order 1000 Public Policy Tx Projects

By Rich Heidorn Jr.

New England’s needs for energy infrastructure, which have been debated in the courts and state legislatures, moved to ISO-NE’s Planning Advisory Committee last week as stakeholders began discussing the potential for major transmission projects under FERC Order 1000.

Although EPA’s Clean Power Plan may be eliminated by the Trump administration, state clean energy goals could drive projects that deliver Canadian hydro and wind power from Maine and the Atlantic Ocean. Order 1000 requires public utility transmission providers to consider “transmission needs driven by public policy requirements [PPR] in both the local and regional transmission planning processes.”

ISO-NE FERC Order 1000 — ISO-NE transmission needs to satisfy renewable public policies | *Avangrid*

ISO-NE last month invited stakeholders to identify public policies that could drive transmission needs, in compliance with the FERC rule. National Grid, NextEra Energy Transmission and TDI New England were among those that submitted ideas before the Feb. 25 deadline.

At the PAC meeting Thursday, the Conservation Law Foundation and Avangrid gave their views, prompting a debate with the New England States Committee on Electricity (NESCOE) over FERC’s and the RTO’s jurisdiction.

“This is a very important program and crucial to both the states’ and [ISO-NE’s] ability to meet their obligations in this area,” said David Ismay, senior attorney for CLF.

Public Policy Drivers

Ismay outlined potential transmission upgrades resulting from:

State renewable portfolio standards, which will require about 20% of ISO-NE load to be served by renewables by 2030;
The 2016 Massachusetts Energy Diversity Act, which mandates procurement of 9.45 TWh of hydro or hydro and RPS by 2022 and 1,600 MW of offshore wind by 2027; and
The Massachusetts and Connecticut Global Warming Solutions Acts of 2008, which require 2050 statewide emissions limits at least 80% below 1990 (Massachusetts) and 2001 (Connecticut) levels.

Ismay said ISO-NE’s 2016 Economic Study — still in development — and the 2015 Economic Study: Evaluation of Offshore Wind Deployment indicate the scale and type of upgrades that could meet the RPS targets and import large amounts of Canadian hydro and offshore wind.

Those studies identified transmission to eliminate bottlenecks between load and wind resources in Maine; a project for moving Canadian hydro to Southeast Massachusetts (SEMA); and transmission to SEMA from the Rhode Island/Massachusetts Wind Energy Area designated by the Bureau of Ocean Energy Management.

“We think there is a need for a north-south connection from Canada, from Maine, from both of those perhaps, to the SEMA load zone and this is a need that has been much discussed,” Ismay said.

Ismay said the RTO should conduct a transmission study to identify “a range of cost-effective” upgrades able to satisfy the state initiatives, adding “I’m sure there’s other ways to do it” beyond those identified in studies to date.

‘Could This Go Anywhere?’

“All well and good,” one stakeholder responded when Ismay finished his presentation. “But if the states have no agreement as to cost sharing, could this go anywhere at all?”

“The way I read the language that’s already in the Tariff and the way I read the FERC orders, this is a process that already has cost allocation in the Tariff for it,” Ismay answered. “The cost allocation can potentially be modified if the states reach agreement, but it’s not dependent on the states reaching an agreement. As the Tariff and the last order from FERC currently stand, it’s clear that this is an ISO process — not one that the states may wholly control but one that they absolutely may contribute to and may drive.”

Dorothy Capra, director of regulatory services for NESCOE, disagreed with Ismay’s interpretation.

“I don’t want to get into a legal argument here, but let’s just say NESCOE disagrees with the way CLF is interpreting Attachment K,” she said, referring to the section of ISO-NE’s Tariff governing the regional system planning process. “We believe that the states do have the right to say whether or not their policies actually require transmission.”

Ismay acknowledged states can challenge public policy declarations. “Say a stakeholder other than the state identifies a valid PPR … and the states say, ‘You know that second one? We’re good. We’ll show you how this doesn’t impact regional transmission.’ I would expect [ISO-NE] to consider that and to weigh that in its assessment,” he said.

Jose Rotger of Emera Energy asked for the RTO’s legal interpretation. “Does the ISO believe that it can begin a public policy transmission study regardless of whether there was a request filed by NESCOE and the states?” he asked.

“I’m not going to do the hypothetical,” responded Theodore Paradise, assistant general counsel for operations and planning. When Rotger persisted, Paradise would not budge. “If this was court, I’d say, ‘Asked and answered.’”

Jurisdictional Challenge to FERC

NESCOE and state regulators from the region have challenged FERC’s May 2013 order accepting ISO-NE’s compliance filing amending its Tariff in accordance with Order 1000’s local and regional transmission planning and cost allocation requirements, as well as the commission’s March 2015 order on rehearing (ER13-193 and ER13-196).

Transmission developer LS Power Transmission and others have also challenged FERC’s rulings, saying the compliance filings by ISO-NE, NYISO and SPP still favor regulated incumbents over independent developers. (See Tx Developers Challenge NYISO, SPP, ISO-NE Order 1000 Filings.)

Order 1000 described PPRs as those “established by local, state or federal laws or regulations (i.e., enacted statutes passed by the legislature and signed by the executive and regulations promulgated by a relevant jurisdiction, whether within a state or at the federal level)” and include “local laws and regulations passed by a local governmental entity, such as a municipal or county government.”

NESCOE said the commission was arbitrary and capricious in “requiring the selection of public policy-driven projects in the regionwide transmission plan, rather than solely the establishment of procedures to consider (i.e., identify and evaluate) transmission projects driven by state and local public policy requirements.”

The committee also said FERC exceeded its authority under the Federal Power Act and violated state sovereignty in expanding the requirements of Order 1000 “from an obligation to consider public policies in transmission planning to an obligation to select policy-driven projects” (15-1139, 15-1141). Oral arguments in the case were held before the D.C. Circuit Court of Appeals on Jan. 13.

Details

Steve Garwood of New Hampshire Transmission asked ISO-NE officials about the level of detail they sought in filings due Feb. 25, noting that the RTO’s template “asks for very specific upgrades.”

Director of Transmission Planning Brent Oberlin said the level of detail provided by CLF is “a start.”

“We laid out the template … hoping for much more specificity,” he added.

In considering transmission projects for Canadian hydropower, for example, “I don’t know what the cost of the [energy] source is … so depending on where I land [the beginning of the transmission line], I may be picking the most expensive generator on the planet. And since the ISO doesn’t procure resources, it’s a little tough to work out.”

Avangrid: Leverage Existing Tx

Also presenting was Avangrid’s Paul Dumais, who highlighted the same public policies as CLF, while also mentioning the Clean Power Plan.

Dumais noted that the region has already made significant transmission investments through reliability projects, saying the RTO should insist that in ensuring sufficient transmission to accommodate public policies “we leverage the investments we’ve already made.”

He also expressed concern over the choice of planning assumptions, saying the RTO should balance reliability against cost.

“For example the assumptions made about generation dispatch in the minimum interconnection standard versus the capacity capability interconnection standard will drive different levels of upgrades,” he said.

“We would encourage NECSCOE … to talk about how … it’s not necessarily needed that the system be designed for the peak day with generation at nameplate rating and the interconnection at New Brunswick flowing at the 1,000-MW [limit]. … What’s more important is that over the 8,760 hours [per year], the generation is generally deliverable into the market. This requires us to look at it differently, such that we’re not building transmission to necessarily meet the worst-case situation — that there’s recognition that at some points in time there’s likely to be some congestion and people can live with that given the cost to overcome it.”

Untangling from CPP

In his environmental regulatory update, ISO-NE’s Patricio Silva gave the PAC a briefing on what he said were the steep challenges facing the Trump administration’s plan to scuttle EPA’s Clean Power Plan.

Silva noted that EPA acted following its 2009 finding that greenhouse gas emissions present a threat to public health and welfare and that the agency had a duty to act.

“It’s a final rule. Withdrawing the finding requires an additional rulemaking and they have to offer a justification to essentially counter the existing regulatory record,” he said. “This approach presents a variety of legal hurdles and some administrative rulemaking hurdles. It is not clear that this would succeed. There are ample example of litigation where such approaches came to naught.”

Successfully withdrawing the endangerment finding would eliminate EPA’s rationale for regulating emissions from existing generators under Clean Air Act Section 111(d) and new units under Section 111(b).

Silva said that could pose a new risk to generators, who have been protected from private litigation over GHG emissions by the Supreme Court’s 2011 American Electric Power vs. Connecticut decision, which said EPA’s regulatory authority over emissions precluded any “private right of action.”

“If EPA determines they do not have the authority under 111, the decision in AEP vs. Connecticut seems to imply … that generators could subsequently be subject to private litigation,” Silva said. “This is a very complicated area of law and regulation that is fraught with significant risk for existing and new generators. … Many of my counterparts at the other ISO/RTOs are watching this matter with a great deal of focus for the potential impacts.”