Page 1032 – RTO Insider

June 7, 2019

Complaint Seeks Bigger Role for Smaller MISO Projects

By Amanda Durish Cook

LS Power filed a complaint Wednesday asking FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV and change its approach to estimating the benefits of smaller projects.

The complaint under Federal Power Act Section 206 requests the commission to order reforms on a 60-day deadline that establish cost allocation for market efficiency projects (MEPs) below 345 kV (EL19-79).

Currently, MEPs must meet a voltage threshold of at least 345 kV and cost at least $5 million. However, MISO earlier this year filed a Tariff revision to lower the threshold to 230 kV, a change that RTO staff have said will reflect the reality of a footprint where 230-kV lines are prevalent. (See MISO MEP Cost Allocation Plan Goes to FERC.)

FERC has yet to rule on the requested change, and LS Power has also filed its complaint in the docket for the associated proceeding (ER19-1124).

In its complaint, LS Power argues that reducing the voltage threshold to 100 kV would “remedy flaws in MISO’s economic planning process” and also expand the number of projects eligible for competition, consistent with FERC Order 1000.

“The commission should require MISO to resolve this issue quickly as it has been aware of this deficiency in its economic planning process for several years and failed to solve it in a just and reasonable manner,” LS Power said.

The company contends that MISO’s planning process fails to provide a “clear path” for regionally beneficial economic projects at lower voltages, resulting in “unnecessary congestion costs and unjust and unreasonable rates.”

Not Far Enough

MISO’s filing does seek to address at least some of LS Power’s concerns by creating a new category for economic projects below 230 kV and above 100 kV for which 100% of costs would be allocated to a local transmission pricing zone, rather than across multiple zones. Such transmission projects were previously categorized as “other” projects without clear allocation rules.

But the company said the RTO’s cost allocation proposal doesn’t go far enough and argued that economic projects below 345 kV can relieve congestion in multiple transmission pricing zones.

“There are not clear criteria or procedures for identifying and evaluating economic projects outside of the Market Efficiency category to determine whether they provide regional benefits and thus should be selected in MISO’s regional transmission plan. As a result, economically beneficial projects may not be identified or may otherwise stall during the planning process to the detriment of ratepayers,” LS Power said.

The company’s complaint goes a step beyond the cost allocation issue, asking FERC to find MISO’s current MEP planning process unjust and unreasonable because it doesn’t outline a path for planning regionally beneficial economic projects that don’t meet MEP criteria. The company also pointed to a substantial amount of 100- to 200-kV facilities in the MISO footprint, saying it’s likely the RTO has overlooked similar smaller projects that would reduce congestion across the footprint.

LS Power also charged that the MEP voltage threshold undermines Order 1000 because such a strict voltage criteria “effectively grants incumbent transmission owners in MISO a federal right of first refusal to build regionally economic enhancements that do not meet the market efficiency project thresholds.”

“It is time for the commission to send a clear message that it will not allow such end runs around Order No. 1000,” LS Power said. While it is difficult to gauge the financial harms related to MISO’s 345-kV voltage requirement for MEPs, the company said it is making a “good faith effort” to estimate the number of projects it may have lost out on.

The company also said it has already raised its MEP-related concerns with both MISO staff and in the RTO’s Regional Expansion Criteria and Benefits Working Group, where cost allocation decisions are made.

LS Power’s Republic Transmission is currently in the process of building the Duff-Coleman 345-kV transmission project in Southern Indiana and Western Kentucky, the RTO’s first competitive transmission project. (See Texas ROFR Law Clouds Hartburg-Sabine Future.)

June 7, 2019

UPDATED PJM: Nukes Keep Energy Costs down, in Theory

By Christen Smith

Three nuclear plants facing early retirements in Pennsylvania and Ohio would keep wholesale energy market net-load payments lower — in most cases — if they stay online, a PJM an a l y sis released Tuesday concluded.

But there’s one caveat: The study’s projections don’t include the costs of potential subsidies.

That point is an important one for critics of out-of-market payments designed to prop up certain forms of generation. Supporters argue, however, that nuclear power’s benefits of reliability and zero-carbon emissions make it stand apart and deserve special consideration.

“The PJM report confirms that consumers and the environment benefit by preserving existing nuclear plants and replacing aging, carbon-intensive coal generation with new renewables and natural gas,” said Paul Adams, spokesperson for Exelon, owner of the nation’s largest nuclear fleet — including the soon-to-be shuttered Three Mile Island near Harrisburg, Pa. The company’s attempt to make the plant profitable through a state-imposed subsidy failed in that state’s legislature last month. (See Exelon to Close Three Mile Island.)

Adams said the report reaches the same conclusions of multiple other analysts and consultants that found “retaining the nation’s existing nuclear plants is the cheapest way to maintain environmental progress and would cost consumers billions less than allowing them to retire.”

But it seems lawmakers and regulatory bodies in both Pennsylvania and Ohio have remained unconvinced that extending the lives of nuclear plants overrides the need to maintain a competitive wholesale electricity market. Both the Pennsylvania Public Utility Commission and the Ohio Consumers’ Counsel requested the PJM study to better grasp the cost and emissions impacts of retiring reactors at Beaver Valley, Davis-Besse and Perry nuclear plants as proposals to enact subsidies for all three still pend before lawmakers.

“It was counter to logic when FirstEnergy Solutions testified in the Ohio House of Representatives that electric consumers would pay more if its antiquated nuclear plants are shut down,” said J.P. Blackwood, spokesperson for the OCC. “PJM’s findings for consumer savings from power plant competition confirm that a competitive generation market is better for millions of Ohio consumers than charging them for bailouts and subsidies under House Bill 6.”

PJM Simulations

PJM obliged the requests by creating six scenarios against which to compare what the RTO considers its base case: all three plants retire, and scheduled gas and renewable generators with an in-service date of 2023 come online, reducing net-load payments by $1.6 billion. Carbon dioxide emissions would likewise decrease by 4.3 million tons, while nitrogen oxide and sulfur dioxide emissions would fall by 37,900 tons and 18,200 tons, respectively, the analysis concluded.

Should all three nuclear plants stay operational and new generation enters the market as planned, net-load payments would decrease by an additional $474 million from the base case. In Pennsylvania, emissions of CO2, NOx and SO2 would decrease from the base case by 4.7 million tons, 5,000 tons and 3,300 tons, respectively. In Ohio, the additional emission reductions total 3.7 million tons, 2,400 tons and 3,500 tons, respectively.

The results are similar — net-load savings increase and greenhouse gas emissions decrease — when either just Beaver Valley or the Ohio plants stay online, PJM found.

Tom Becker, a spokesperson for FirstEnergy Solutions, the bankrupt company that owns Davis-Besse and Perry, said Wednesday that the simulations confirm that their plants provide valuable benefits to Ohio, including $30 million in annual state and local tax revenues, a diversified resource mix, 4,300 jobs and 90% of the state’s zero-emission energy.

PJM went a step further, however, and modeled the impact of a 50% reduction in new gas-fired generation coming online as a reaction to nuclear subsidies entering the market.

If all three plants remain operational and planned gas projects decline by half, net-load payments would decrease by $91 million from the base case.

“This is because the retention of all the nuclear plants and their associated energy production is sufficient to offset the impact of the reduced new entry,” the study noted. “This reduction in customer payments, however, is not netted against the cost of a potential subsidy to consumers in a particular state.”

Under that scenario, carbon emissions would likewise plummet from the base case by more than 9.5 million tons in both states combined with smaller decreases in NOx and SO2.

If either state retires their plants while the other’s stay online, however, net-load payments increase from the base case by between $164 million and $240 million. Emissions would still decrease in Ohio, but Pennsylvania’s NOx and SO2 emissions would both rise, because of the reliance on less efficient coal-fired generation in the absence of new gas units.

Joe Bowring, PJM’s independent market monitor, said Thursday the latter scenarios — losing only a few of the plants and at least half of the planned gas generation — are far more likely than the other simulations.

“Those models are a lot more realistic,” he said. “I would have discounted the new gas units even more than 50% [to account for impacts of potential subsidies].”

Subsidy Plans Alive in Both States

It’s not clear how PJM’s analysis will move the needle — if at all — in the state legislatures, where plans to subsidize all the plants still remain active.

Ohio’s proposed Clean Air Program was still pending before the Senate as of Wednesday, one week after the lower chamber approved the controversial measure to effectively gut the state’s renewable portfolio standards in favor of ratepayer fees for FirstEnergy’s nuclear plants. (See Ohio Plan Subs Nuke, Fossil Fuels for Renewables.)

Meanwhile, a bill to expand Pennsylvania’s Alternative Energy Portfolio Standard to include nuclear power languishes in the House Consumer Affairs Committee while lawmakers tend to the annual budget, due June 30. The delay meant the bill couldn’t save TMI, but state officials said that doesn’t mean the issue is dead. (See Nuclear Subsidies Still on the Table in Pennsylvania.)

June 6, 2019

Texas ROFR Law Clouds Hartburg-Sabine Future

By Amanda Durish Cook

The future of MISO’s second-ever competitively bid transmission project could be in jeopardy after passage of a Texas law that grants incumbent utilities the right of first refusal (ROFR) to build projects within the state.

MISO last year selected NextEra Energy Transmission Midwest to construct the Hartburg-Sabine Junction 500-kV project in East Texas. NextEra proposed to spend $115 million to build the project, which would consist of a new 23-mile single-circuit 500-kV line, four 230-kV lines and a new substation. The company sought a $95 million transmission revenue requirement (TRR), and its winning proposal scored 97 out of a possible 100 points in the bidding process. (See NextEra Wins Bid to Build MISO ’s 2nd Competitive Project.)

But the new Texas law casts doubt on NextEra’s ability to proceed with the highly anticipated market efficiency project. Gov. Greg Abbott signed the ROFR bill into law May 17 after the state House of Representatives voted 139-5 to pass it and it cleared the Senate 31-0.

Referring to ERCOT’s historical exemption from FERC oversight, Rep. Dade Phelan (R), a sponsor of the bill, told legislators in May that the bill will “ensure the Public Utility Commission, and not the federal government, will have jurisdiction over Texas transmission rates.” (See Texas ROFR Bill Passes, Awaits Governor ’s Signature.)

But opponents contend the law will undercut competition by prohibiting anyone but incumbent utilities to build Texas transmission and prevent the PUC from licensing new entrants to the transmission market.

MISO says it is reviewing the developments but still expects construction will proceed on the congestion-relieving line.

“MISO is committed to delivering the benefits of the Hartburg-Sabine Junction 500-kV transmission project in East Texas in accordance with its regional transmission plan and in compliance with applicable laws and regulations,” Director of Strategic Communications Julie Munsell told RTO Insider. “MISO is reviewing the applicable Tariff provisions and will determine the appropriate steps.”

The RTO emphasized that its studies show the project will “alleviate longstanding energy congestion issues and import limitations, allowing lower-cost generation to serve customers in the area.”

MISO representatives declined a request for further interview on the matter.

In 2016, MISO respected Minnesota’s existing ROFR when it declined to open the $80.9 million Huntley-Wilmarth 345-kV line project to competitive bidding. At the time, MISO’s legal team said the RTO must respect state and local laws. (See Courts Uphold Minn. ROFR, MISO Cost Allocation.)

Big, Swift Change

In testimony in April, NextEra Energy Transmission President Aundrea Williams said that if the Texas ROFR legislation passed, it would “without question” force customers in East Texas to “pay more for this key transmission project and lose out” on benefits because of the lack of competition. Williams also said the MISO competitive process found that NextEra’s proposal would save customers tens of millions of dollars when compared to other proposals. She cautioned that the bill would have “real detrimental” consequences for Hartburg-Sabine.

“This bill is a big change to Texas transmission markets, and a swift change. A change so big it that it will have an impact on every single Texan and so fast that there is insufficient time to have an opportunity to fully evaluate all the possible negative implications that will ripple across the state. The bill will impair a longstanding market fundamental that underpins the overall structure of the Texas electricity market that has served Texans well for many years,” Williams said.

Incumbent transmission owner Entergy was one of 12 developers to bid on the project under its EasTex TransCo subsidiary. While MISO does not release specific details about losing proposals in competitive solicitations, general data released by the RTO regarding Hartburg-Sabine showed submitted bids ranged from $95.4 million to $133.9 million, while TRRs ranged from $88.2 million to $166.3 million.

Entergy did not respond to an inquiry about its proposal or its intentions regarding the project in light of the ROFR law. NextEra also declined to comment for this story.

In March, FERC granted NextEra an abandoned plant incentive, allowing the company to cover 100% of its investment if the Hartburg-Sabine project is canceled for reasons outside the company’s control. (See NextEra Gains Incentive for Hartburg -Sabine Project.)

June 6, 2019November 2, 2023

Legal Scuffle Threatens Virginia Tx Line

By Christen Smith

A three-judge D.C. Circuit Court of Appeals panel said last week the Surry-Skiffes Creek transmission line in Virginia can remain operational — for now — while the legal battle over the U.S. Army Corps of Engineers’ permit for the $400 million project ensues in a lower court, where judges could ultimately force Dominion Energy to tear it down.

In March, the panel said the corps violated the National Environmental Policy Act by not issuing an environmental impact statement (EIS) and vacated the permit for the project, which crosses the James River and passes in close proximity to several historic parks and trails “dating back to the birth of our nation.”

In an appeal, the corps and Dominion did not dispute that the permit was illegal, but they requested the court remand the project back to the corps without vacating the permit, saying the court did not “have before it the recent factual developments regarding completion of construction and the disruption that vacating the permit could cause.”

“That, of course, is because neither petitioner bothered to advise us that construction on the project had been completed and the transmission lines electrified the week before we issued our opinion,” the judges said in their March 31 decision.

The National Parks Conservation Council and National Trust for Historic Preservation had originally appealed the permit in the D.C. District Court. Opponents have contended the line will ruin the view at Jamestown and other nearby historic sites, dismissing as a scare tactic Dominion’s warning that failure to build will result in blackouts in Virginia’s middle peninsula. (See Opposition to Va. Tx Line May Trigger Unintended Consequences.)

The corps and Dominion argued the permit should stand and the 500-kV line should stay in service to maintain reliability and provide power to the 600,000 residents on Virginia’s peninsula. PJM first greenlit the project in 2012 as the best solution to fill the gap left behind by the retirement of two coal-fired plants in Yorktown deemed incapable of meeting federal emissions standards. Dominion electrified the line in February and wants to keep it operational while the corps conducts the court-ordered EIS, slated to take at least a year to complete.

The D.C. Circuit remanded the case back to the district court to decide whether the request is even feasible. It admonished the utility company and the corps for not notifying it that the project was finished before it made its decision.

“Had the corps and Dominion said all along what they say now, either the district court or this court might have enjoined tower construction, in which case our consideration of ‘disruptive consequences’ … would focus not on shutting down and removing the towers, but rather on prohibiting their construction — a very different balance indeed,” the panel said. “Moreover, having completed construction, petitioners now attempt to use it to place an even heavier thumb on the scale.”

The plaintiffs argued that by not disclosing that the project was operational before the court made its decision, the corps and Dominion had waived their right to argue that vacating the permit would be too disruptive. They noted that to defeat their motion to prevent construction, the corps and Dominion had assured the lower court if it required the corps to issue an EIS, the project could be dismantled without a problem. The circuit court said this was “more than a little troubling.”

However, “we nonetheless believe the best course of action is to remand the case to the district court to consider … whether vacatur remains the appropriate remedy, including whether [the corps and Dominion] have forfeited or are judicially estopped from now opposing vacatur,” the D.C. Circuit said. “That court is best positioned to order additional briefing, gather evidence, make factual findings and determine the remedies necessary to protect the purpose and integrity of the EIS process.”

Paul Edmondson, interim president and CEO for the Nation Trust for Historic Preservation, applauded the ruling in a statement last week, noting the decision underlines “the historic significance of the James River.”

“There are feasible alternatives to this transmission line, but there’s only one Jamestown,” he said. “With vast resources at its disposal, Dominion should do the right thing by deconstructing these towers and working to provide reliable power in a way that does not come at the expense of America’s birthplace.”

Analysts with ClearView Energy Partners believe the lower court — or the results of the EIS — could indeed force Dominion to dismantle the project and reroute it, spawning a cascade of possible service disruptions and reliability concerns. On a broader scale, analysts warn the project’s outcome sets a precedent for what happens when federal agencies do not follow statutes and regulations, ultimately increasing the risks for transmission project developers.

June 6, 2019

NYISO Reports Grid Ready for Summer

NYISO said Wednesday it expects to have adequate resources on hand to meet slightly above-normal demand this summer, with 42,056 MW of capacity available to meet a forecasted peak of 32,382 MW.

The figures show the ISO will far exceed its capacity requirement of 35,002 MW, which includes an operating reserve requirement of 2,620 MW.

“The state’s grid is well-equipped to handle forecasted summer demand,” said Wes Yeomans, NYISO vice president of operations, said in a statement. “We have performed on-site visits of key generating stations to discuss maintenance, testing and adequacy of fuel supplies for hot-weather operations.”

The ISO’s projected summer peak is 1.5% above the 10-year average and outpaces last summer’s actual peak of 31,861 MW recorded on Aug. 29 (and the 2017 peak of 29,677 MW) but is down from the 2018 peak forecast 32,904 MW. Demand topped 31,000 MW on six days last summer.

The peak is calculated to reflect normal summer conditions, but under more extreme weather scenarios peak demand could increase to about 34,186 MW, NYISO estimates. The ISO’s record peak of 33,956 MW occurred in July 2013 at the end of a heat wave.

The total capacity of power resources available to New York this summer include 39,295 MW of generating capacity from in-state power plants, 1,309 MW of demand response resources and 1,452 MW of imports from neighboring regions. The forecast factors in the expected impact of distributed resources and energy efficiency programs.

NYISO staff and the New York Department of Public Service last month informed the state’s Public Service Commission on summer electricity preparedness. (See “Grid Prepared for Summer,” NYPSC Modifies Standby Rates for DERs.) The department forecasts summer energy prices will be down 1 to 3% compared with last year, depending on load zone and weather conditions.

– Michael Kuser

June 6, 2019

NECPUC Day 2: McNamee Reiterates Storage Dissent

By Michael Kuser

HARTFORD, Conn. — FERC blurred the line between state and federal oversight over power issues last month when it rejected multiple requests to reconsider its landmark electric storage order, Commissioner Bernard McNamee told the New England Conference of Public Utilities Commissioners (NECPUC) at its 72nd annual symposium Tuesday.

The May ruling prompted a partial dissent from McNamee over the commission’s rejection of requests to allow states to opt out of rules giving FERC jurisdiction over storage resources connected to utility distribution systems (Order No. 841-A). (See FERC Upholds Electric Storage Order.)

“I dissented partially from this order because I felt that for behind-the-meter storage resources and those resources that are connected at the distribution system, FERC exceeded its authority,” McNamee said.

NECPUC — FERC Commissioner Bernard McNamee addressed the New England Conference of Public Utilities Commissioners at its 72nd annual symposium June 4 in Hartford, Conn. | © *RTO Insider*

The Federal Power Act took a two-pronged approach, giving FERC authority to make decisions about the transmission of electric energy in interstate commerce and the sale of electricity at wholesale, while also recognizing states’ jurisdiction over generation and distribution facilities, he said.

“The majority of the commission reasoned that because energy resources would affect wholesale prices, FERC had jurisdiction to tell the states that they had to allow energy storage facilities to connect at the distribution level and, by the way, saying, ‘You figure out the safety issues,’” McNamee said. “I fundamentally thought that was exceeding our authority.

“Where is the line between the states and the federal government on these issues?” he continued. “What’s the policy about this? What do the parties say of this? What is the legal thinking from the parties about this? I’m trying to decipher that.”

Issued in February 2018, FERC Order 841 set a Dec. 3, 2019, deadline for RTOs to comply with the directive to allow storage resources to provide any services of which they are capable. The commission in February approved FERC Accepts ISO-NE Storage Tariff Revisions.)

Utility-scale or not

The anticipated rapid growth of storage was a hot topic at the conference, with ISO-NE last month confronting 2,500 MW of storage resources in its queue, compared with 1,381 MW just a month earlier. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)

“Our interconnection queue doesn’t mean all those projects will get built,” said Christopher Parent, ISO-NE’s director of market development, adding that the RTO will focus on bringing storage projects into the market.

“Sometimes behind the meter, sometimes in front … our market constructs enable all storage to participate and select the services it provides,” Parent said. “It’s important to get the price signals right for the market.”

Mike Calviou, National Grid senior vice president for strategy and regulation, said his company will own and operate 25 MW/146 MWh of storage by the end of the year.

“We’re also interconnecting non-utility scale storage and have 17 MW paired with solar and 1 MW in the queue,” Calviou said.

The utility put a 6-MW/48-MWh storage facility on Nantucket to back up a diesel generator and avoid the need to build more costly transmission lines.

“We’re working with ISO-NE to maximize benefit, so you don’t just write incentives to create storage but to use it,” Calviou said.

“I think storage should be seen as part of the solution,” he said, adding that planners should not be technology-agnostic.

Jeffrey Bishop, CEO of storage developer Key Capture Energy, which has 10% of the storage in ISO-NE’s queue, said, “If the wholesale market doesn’t have the right incentives to support storage development, the states will step in and do that. Massachusetts has its Clean Peak Standard because the wholesale market doesn’t compensate for the various services that storage provides.”

Massachusetts mandates that electricity suppliers serve a certain portion of their sales with “clean peak” resources, with the state’s Department of Energy Resources each year determining the minimum standard. (See Mass. Inaugurates Clean Peak Standard.)

Lon Huber, a director at energy consultancy Navigant, cited time-of-use rates as evidence of how storage is moving from environmental value to systemwide benefit value.

Storage can respond to price signals at the peaks, Huber said, noting how fossil fuel-fired generators were unable to work in a cold snap and “should be penalized for not providing capacity when needed.”

Time-of-use rates are the tool that allow customers to shift their demand to shoulder periods, said Anne Hoskins, chief policy officer for solar developer SunRun.

“In two years, we’ve seen a dramatic increase in customer demand for storage,” yet in some ways the system is living in the past, Hoskins said. “During the wildfires there was a massive rush on generators … and it was very disconcerting to me, living in California in a fire district, to receive a notice from my utility that said ‘Be prepared for the shutoffs, and get your gasoline for your generator.’ And this is in a state where climate goals are very high, like the climate goals here.”

Connecticut Public Utilities Regulatory Authority Chair Marissa Gillett confessed that her state is one of three in the region (along with Rhode Island and Maine) that do not yet support a “bring-your-own-device” (BYOD) program.

BYOD offers utility customers rebates for installing and enrolling connected thermostats and battery energy storage devices.

“The New Hampshire public consumer advocate supported BYOD, but not my own state,” Gillett said.

Hoskins said that despite the slow start in some states, “New England is showing tremendous leadership in this area … and it takes a lot of legwork to set the tariffs.”

She noted that neighboring NYISO is also active on the issue, and that PSEG Long Island in the next couple of weeks is about to launch its own BYOD program.

(For Day 1 coverage of the NECPUC event, see New England Regulators Talk Wholesale Market Evolution.)

June 6, 2019

NERC Operating Committee Briefs: June 4-5, 2019

ORLANDO, Fla. — The NERC Operating Committee approved the following in meetings Tuesday and Wednesday:

The Resources Subcommittee’s revised reliability guideline on primary frequency cont rol under BAL-001-TRE-1 and PRC-001-WECC-CRT-2. Originally published in 2015, the guideline’s definitions were updated and the section on recovery periods was expanded. Applicable to: balancing authorities, generator operators (GOPs), generator owners (GOs), transmission operators (TOPs) and transmission owners.
The Data Exchange Information Requirements Task Force’s compliance guidance on data exchange infrastructure and testing requirements under TOP-001-4 R20, R21, R23 and R24, and IRO-002-5 R2 and R3. Includes clarification of “redundant and diversely routed” language and testing requirements. Applicable to: TOPs, BAs and reliability coordinators.
The Real–time Assessments Quality Task Force’s compliance implementation guidance on the quality of analysis used in completion of a real-time assessment under TOP-010-1(i) R3 and IRO-018-1(i) R2. Applicable to: TOPs, RCs and applicable supporting entities.

The committee also authorized the posting of the Event Analysis Subcommittee’s revised ERO Events Analysis Process for a 45-day industry comment period. Version 4.0 adds: information on weather-related events; references to inverter-based resources in Categories 3 and 4 events; and expanded appendices. Applicable to regional entities and registered entities (e.g., TOs, GOs, load-serving entities).

IRPTF Scope Document Remanded

Task force Chair Allen Schriver, of NextEra Energy, said the new document was a spinoff of the group’s September 2018 reliability guideline: BPS-Connected Inverter-Based Resource Performance.

“The [inverter] manufacturers kept telling us, ‘Nobody told us what they wanted.’ … So we wrote this performance guideline, and industry came back to us and said, ‘Can you turn that into interconnection requirements?’”

Schriver said the new document recommends improvements to both performance and modeling requirements. “Modeling is still an issue we have with solar sites in providing the correct models for how the site operates,” he said.

The committee postponed a vote on a revised scope document for the task force. OC Chair Lloyd Linke said he, Planning Committee Chair Brian Evans-Mongeon and task force leaders agreed that “the product of the task force is still too vaguely defined.”

Rich Bauer, NERC’s associate director of reliability risk management-event analysis, suggested the committee consider converting the task force into a working group, saying there is no clear end to the task force’s work.

“What we discovered was, once we got the task force together and we started talking about momentary cessation, every time we talked about something … there’s something else that crops up that we didn’t know, we didn’t understand, that we need to have more work on,” he said. “Inverter-based resources are changing our lives in the way that we operate the system. … The work that we’re doing is not just a specific function with borders. It is a body of work that is ongoing, at least for the near future.”

Linke’s Poignant Farewell

Linke received a standing ovation from the committee after concluding the final meeting of his two-year term as chair. The Western Area Power Administration vice president of operations choked up as he recalled his tenure.

WAPA’s Lloyd Linke received a standing ovation at his last meeting as Operating Committee chair. | © *ERO Insider*

He said the IRPTF’s high-profile work in response to the Blue Cut Fire and work by other special task groups “overshadowed a lot of our normal day-to-day activities in ensuring reliability.”

“I’m just hoping that … we’re still able to do the reliability work we’ve done in the past,” after the proposed reorganization that could combine the OC with the Planning Committee and the Critical Infrastructure Protection Committee. (See “Potential Change to Committee Structure,” NERC MRC, Trustees Meeting Briefs: May 8-9, 2019.)

WAPA’s Lloyd Linke concluded his two-year term as chairman of the NERC Operating Committee. | © *ERO Insider*

Asked after the meeting whether he feared the committee’s role could be diminished, Linke responded, “The devil is in the details.”

“That process can move forward and be totally successful. I don’t have any doubts about that,” he continued. “But it’s also going to lead to a period of turmoil, which all change creates. And … how that group deals with that turmoil and drives through that turmoil would have an impact on their capabilities. The key is in the subcommittees. As long as the activities of the subcommittees is not significantly disturbed, [it will be OK].”

MISO’s David Zwergel was elected to succeed Linke as chair for 2019-2021. Doug Hils of Duke Energy was elected to succeed Zwergel as vice chair.

Nominations for the annual OC election will be accepted through June 24.

June 5, 2019

Costco Stays with Dominion, Va. Commission Rules

By Christen Smith

In a ruling that highlights growing rifts in Virginia’s electricity sector, the State Corporation Commission rejected Costco’s bid to buy power from utilities across state lines, saying that keeping the retail giant a customer of Dominion Energy best serves the public interest.

The SCC ruli n g handed down June 1 prevents the company from aggregating its total electricity consumption to take advantage of a 2007 state law that allows large-scale customers with a peak demand of 5 MW or higher to shop around for suppliers The law provides the SCC with broad discretion for how to apply it.

While the commission agreed with Costco’s contention that Virginia’s regulatory framework supports unjustified rate hikes, it shifted the burden onto the state legislature to solve the issue of rising energy costs.

The SCC noted Dominion’s “rate-captive” customers have faced “a decade of rising rates and the likelihood of even higher rates in the future.” Allowing Costco to abandon Dominion under existing rules, the commission said, would force other ratepayers to make up the $1.57 million in lost annual revenues.

Although the state law enshrines an “escape valve,” the SCC determined it unfair for Costco to save money “at the expense of other customers.”

“This Commission will not allow small customers who cannot escape this structure, predominantly small businesses and residential customers, to be further burdened by the identified cost-shifting that will occur if larger customers like Costco choose to seek better deals for themselves outside of Dominion’s system,” the SCC wrote.

Costco argued “a wave of commercial customers leaving the utility through aggregated retail choice” would encourage Dominion to stop hiking prices to fund expensive system upgrades — often incompatible with clean energy goals. The commission denied Walmart’s request in February, while petitions from Target, Kroger, Harris Teeter and Cox Communications remain outstanding.

In the filing, a Costco witness accused Dominion of “over-earning on its frozen base rates for a number of years,” creating an “enormously frustrating” incentive “to keep what I view as the customer’s money.”

Costco’s comments underscore the rising tension between retail choice advocates and Dominion Energy, Virginia’s dominant utility company and most generous corporate campaign donor. Last month, a coalition of unlikely allies launched efforts to bust up the company’s monopoly — more than a decade after state lawmakers officially abandoned the deregulated electricity market design — insisting its well-funded lobbying efforts leave ratepayers footing the bill for wasteful infrastructure spending. (See Va. Group Seeks End to Dominion M onopoly.)

Dominion contributed more than $452,000 to state candidates and committees last year, according to the Virginia Public Access Project, making it the commonwealth’s largest campaign donor within the energy sector. That same year, the utility also advised lawmakers on an overhaul of its regulatory framework that allowed it to invest a larger share of revenues in new projects, rather than refunding customers for “overpayments” — as the SCC often made the utility do in years past.

Greg Morgan, Dominion’s general manager of regulatory affairs, said companies only began using the aggregation clause to pursue retail choice last year, despite its existence since 2007.

The utility also defended its infrastructure investments during an interview Tuesday, citing plans for six new solar facilities with a combined 350-MW capacity in Virginia and North Carolina, scheduled to come online in 2020. Dominion also supports cutting greenhouse gas emissions in half over the next decade and by 80% by 2050.

When it comes to the SCC’s decision, Dominion agreed it best protects customers from the shifting burden of costs while still supporting the diversification of the utility’s energy portfolio to include more renewable resources. Le-Ha Anderson, a Dominion spokesperson, said the company offers many different rate structures for customers unhappy with costs — a much more reasonable alternative than leaving the company altogether.

June 5, 2019

CAISO’s RC West Earns NERC Certification

By Robert Mullin

CAISO said Monday its RC West operation has achieved a “major milestone” after attaining the NERC certification needed to begin providing reliability coordinator services to balancing authorities in California and parts of Mexico on July 1.

The certification — issued by the Western Electricity Coordinating Council through its delegated authority from NERC — marks a key step in transitioning RC oversight of the Western grid away from Peak Reliability, which last summer announced it would be ceasing operations by the end of 2019.

“The NERC certification is an important turning point in our effort to become the reliability coordinator for the Western region,” CAISO CEO Steve Berberich said in a statement. “This was a huge lift for our staff since beginning this venture in January 2018, and the certification speaks to the dedication and hard work across the organization.”

In early January 2018, CAISO announced it would “reluctantly” depart from Peak Reliability and create its own RC — just a month after Peak floated its plan to develop an organized electricity market in partnership with PJM, competing with the ISO’s own expansion efforts. (See CAISO to Depart Peak Relia b ility, Become RC.) By last July, it was evident Peak would lose most of its customers to CAISO’s lower-cost services, prompting the Vancouver, Wash.-based company to begin winding down its own operations and pull out of the joint effort with PJM. (See Peak Reliability to W ind Down Operations.)

Since then, CAISO has worked quickly to stand up RC West as the Western Interconnection, facing the uncertain journey of moving from two to five RCs, with SPP, BC Hydro and Gridforce also sharing in the carve-out of Peak’s former territory. (See RC Transition Fraught with Pitfalls, WECC H e ars.) The Alberta Electric System Operator has historically acted as its own RC and will continue to do so after the dissolution of Peak.

WECC conducted its full certification review of RC West in late March, which consisted of an onsite visit by observers from WECC, NERC and one other RC, as well as at least one BA and transmission owner. During the process, RC West staff were required to provide any requested documentation and answer questions intended to demonstrate readiness for taking on the RC function.

RC West operators have been shadowing Peak’s operations since May 1, taking part in nearly every call, including an energy emergency alert event occurring just hours into the process, Director of Operations Tim Beach told the RC Oversight Committee last month (See RC West Moving Smoothly Toward July Han d over.)

The shadowing process also has RC West staff “verifying system data, conducting operational analysis and monitoring system conditions using situational awareness tools,” CAISO said Monday. The RC function now includes 17 full-time operators working on rotating shifts, with one position still open.

Beginning July 1, RC West will become the RC for 16 California BAs and transmission owners, as well as CENACE in northern Mexico. A second certification review is slated for August, ahead of RC West taking on 24 additional entities on Nov. 1. By then, it will have assumed oversight for about 87% of the West’s load.

SPP and Gridforce last month both said they’re on track to begin shadow operations with Peak in August in preparation for a Dec. 3 transition date. BC Hydro will take over RC functions within its own British Columbia territory Sept. 2 after commencing shadow operations in July. (See New RCs Tell WECC Tra n sition on Schedule.)

June 5, 2019

NERC Sees Summer Risks for Texas, Calif.

By Rich Heidorn Jr.

ORLANDO, Fla. — Most regions have sufficient resources to meet anticipated loads this summer, but Texas and California are at risk from potential natural gas shortages and wildfires, NERC reported Tuesday in its 2019 Summer Reliability As s essment.

The report, which covers June through September, noted ERCOT’s warning it may have to issue energy emergency alerts to respond to resource shortfalls as its summer reserve margin has fallen to 8.5%. (See ERCOT : More Capacity, but Emergency Ops Still Expected.)

Meanwhile, natural gas supply from interstate pipelines will be insufficient to power electric generation on summer peak load days in Southern California, requiring withdrawals from the Aliso Canyon storage facility. NERC also cited concerns over Southern California’s ramping capacity and transmission line shutdowns during wildfires.

ERCOT

ERCOT’s reserve margin dropped from 10.9% a year ago, the result of continued demand growth, delays in planned generation and the mothballing of the 470-MW Gibbons Creek coal-fired generator.

Although its 2018 reserve margin was below its reference margin of 13.75%, ERCOT survived without calling emergency alerts thanks to “high levels of generator availability, response to market signals and unit performance,” NERC said.

ERCOT’s operating plans include voluntary load reductions and power imports if needed.

ERCOT’s summer Seasonal Assessment of Resource Adequacy (SARA), released last month, said the grid operator may tap load resources that can provide operating reserves, use contracted emergency response resources and instruct utilities to employ load management and distribution voltage reductions. It may also import emergency power across its DC ties and ask switchable generators serving ERCOT neighbors to prioritize it instead.

Ramping Concerns

In CAISO, NERC warns of shortages in resources with upward ramping capability, which it said could mean the need for imports to maintain system frequency and prevent load loss in late afternoons as solar generation output drops while loads remain high. “Should extreme temperatures extend over a large area to the point where neighbors lack surplus energy, load could be at risk from a shortage in ramping capability,” NERC said.

NERC said gas-fired generators in Southern California will need to tap fuel from storage because interstate pipelines may not be sufficient to meet peak loads. As a result, withdrawals from the Aliso Canyon natural gas storage facility would be necessary to ensure adequate fuel for generators in the area.

Restrictions on Aliso Canyon “remain an item of focus,” NERC said. High storage withdrawals during winter 2018/19 has meant below-average storage levels this summer.

“The Southern California Gas Company (SoCalGas) forecasts that it will be able to meet the forecasted peak day demand under a ‘best-case’ supply assumption even without supply from Aliso Canyon,” the report said. “However, under a worst-case supply assumption, supply from Aliso Canyon will be necessary to meet that forecasted peak day demand. Should operating restrictions result in natural gas supply curtailments that affect electric generation in the Southern California area, mitigation procedures that have been in place since 2016 can be used to maintain BPS reliability.”

Wildfires

NERC is also citing government warnings of an elevated risk of wildfires in the Western U.S. and Canada, noting utilities’ plans include shutting down transmission lines.

The April-June outlook from the National Interagency Fire Center, Natural Resources Canada and National Meteorological Service in Mexico predicted above-normal wildfire potential for California, the Pacific Northwest (Western Oregon and Washington), Western Alberta, British Columbia and Northern Mexico, NERC said.

In addition to preemptively de-energizing transmission lines in high-risk areas, utilities are using “enhanced vegetation management, equipment inspections, system hardening and added situational awareness measures,” NERC said.

Nevertheless, NERC said the risk of resource shortfalls in CAISO is lower this year than last summer, citing well above normal reservoir levels and mountain snowpack for “greatly reducing the potential for operating reserve shortfalls.” (See CAISO Predicts Plentiful Hydro, Gas C onstraints.)

If CAISO activates its emergency operating plan — for example, in response to the inability to meet spinning reserve requirements — it will employ a number of mitigation measures to minimize loss of load, NERC said including the following:

The Flex Alert program, which can reduce peak loads
The Restricted Maintenance program to reduce forced outages
The performance of manual post day-ahead unit commitment and exceptional dispatch of resources under contract to serve load and meet ramping requirements
The performance of manual exceptional dispatch of intertie resources with resource adequacy obligations to serve CAISO load
The use of demand response programs, including the Reliability Demand Response Resources (RDRR) under the “Warning” stage
The performance of manual exceptional dispatch of physically available resources not under capacity contract