Page 1338 – RTO Insider

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.”

February 28, 2017

MISO Advisory Committee Briefs

Stakeholders last week continued discussions on MISO’s pseudo-tie approval process, even after narrowly approving more stringent requirements in December.

In a Feb. 22 Advisory Committee conference call, stakeholders learned that MISO did not file the proposed pro forma pseudo-tie agreement and Business Practices Manual language with FERC, as originally planned after the 5-4 approval by the Reliability Subcommittee on Dec. 16. There were 13 abstentions on that vote. (See MISO Stakeholders Narrowly Support New Pseudo-Tie Rules.) The RTO cited the narrow margin of victory and the fact that abstentions outnumbered ‘yes’ and ‘no’ votes in its decision to postpone a filing to better explain the proposed process to stakeholders.

Advisory Committee Chair Audrey Penner said the topic was brought back to the committee for more discussion at the request of stakeholders. She said no action was required under the Stakeholder Governance Guide, and the item was placed on the agenda only to bring it to the attention of the committee. “This doesn’t happen very often,” Penner said.

“It really signals that more stakeholders were interested in getting more information from MISO,” Vice Chair Tia Elliott said.

MISO advisory committee pseudo-tie — AC Vice Chair Tia Elliot (L) and AC Chair Audrey Penner | © *RTO Insider*

The proposed rules dictate that pseudo-tie owners notify MISO a year in advance of implementing a new pseudo-tie and create a congestion management process; the rules also say proposed pseudo-ties can be rejected if a market-to-market flowgate is not within 2% of MISO and the neighboring market’s calculated generator-to-load distribution factor.

Penner said MISO will not revoke existing pseudo-ties that fail the 2% test. “MISO believes that all pseudo-ties currently meet this requirement, and that’s why it won’t be retroactively applied,” Penner said.

Reliability Subcommittee Chair Tony Jankowski said he has not heard from MISO staff on whether the issue will be brought up for more discussion in his subcommittee. Stakeholders and the RTO are currently creating agenda items for the next subcommittee meeting in April.

Entergy’s Matt Brown said his company voted against the pseudo-tie proposal because of incomplete information but would consider a better documented agreement, even one with a requirement more stringent than the 2% threshold.

Committee to Hold Current Events Discussions

The Advisory Committee will begin holding quarterly current events discussions in response to stakeholder calls for more in-depth policy conversations.

Penner said the committee will set aside time for discussions of policy issues and industry trends beginning at the next in-person meeting in New Orleans on March 22. Penner said she envisioned committee members tackling no more than two topics per meeting. The quarterly discussion format arose from MISO’s stakeholder redesign. (See MISO Takes Stakeholders’ Temperature on Redesign.)

American Electric Power’s Kent Felix said he viewed the discussions as another opportunity for stakeholders to guide MISO on policy issues. WEC Energy Group’s Chris Plante asked if the committee’s stakeholder sectors might vote to express positions on the topic. Penner said committee leadership had not discussed the possibility of voting during the discussions, but it could be explored.

Madison Gas and Electric’s Megan Wisersky asked if the discussions would be recorded in minutes. Penner said she would take notes, as she could not partake in the discussion as chair, but said it remains to be seen if there would be formal notetaking from MISO.

Penner asked for topic ideas for the first discussion by March 1.

Steering Committee Able to Approve Charters, Management Plans Again

Stakeholders approved a correction to the Stakeholder Governance Guide that restores the Steering Committee’s power to approve charter and management plans.

Elliott said edits approved in December inadvertently deleted a sentence that delegated charter and management plan review for MISO parent committees to the Steering Committee.

“If we don’t get to this change, the Advisory Committee will have to approve all of the charters,” Elliott said.

After its powers were restored, the Steering Committee approved by consent several charters or management plans, including those governing the Market Subcommittee, the Seams Management Working Group, the Resource Adequacy Subcommittee, the Loss of Load Expectation Working Group, the Planning Advisory Committee, the Planning Subcommittee and the Interconnection Process Task Force.

— Amanda Durish Cook