A federal judge approved FirstEnergy Solutions’ reorganization plan last week after the company reached a settlement with workers at its Perry and Beaver Valley nuclear plants to preserve union contracts post-bankruptcy.
According to documents filed in the U.S Bankruptcy Court in Akron, Ohio, FES will keep pensions for existing employees as detailed in collective bargaining agreements with the Utility Workers Union of America and the International Brotherhood of Electrical Workers. The deal calls off the utility’s original plan to renegotiate the unions’ contracts and transfer employees into a 401(k) retirement fund after claiming the company could no longer afford pensions. (See FES Seeks Bankruptcy, DOE Emergency Order and Labor Dispute Stalls FES Reorganization.)
“This is a remarkable victory for workers and unions,” Joyce Goldstein, attorney for both unions, told RTO Insider in an email on Monday. “The agreement reached between the debtors and the unions means that the workers do not lose a penny on their pensions, their wages or any other benefits.”
The news comes six weeks after Judge Alan M. Koschik told lawyers for FES he could not approve its reorganization plan — which included shedding $3.6 billion in debt, cutting ties with former parent company FirstEnergy Corp. and possibly changing its name — until the issue was resolved.
FirstEnergy Solutions won court approval for its restructuring plan last week.
“This is a landmark day in the history of our company,” FES CEO John W. Judge said in a statement Tuesday. “We are now in a position to successfully conclude the Chapter 11 process and will emerge from the restructuring as a fully independent energy company well-positioned to continue serving the needs of our 800,000 customers.”
Judge said more than 93% of creditors approved the restructuring plan, keeping the company on track to exit bankruptcy proceedings before year’s end.
FES also agreed to pay $400,000 in attorneys’ fees for the unions. FES attorney Lisa Beckerman told the court last week without Goldstein’s advice “it would have been very difficult to resolve the complex legal and contractual issues regarding the modifications to the collective bargaining agreements.”
“You know, we feel that it took a long time, but we’re happy that we were able to ultimately reach a deal with our workforce,” she said.
Goldstein described the resolution as a “national success story” in line with strikes organized by teachers and Marriott employees within the last year. In the latter case, 8,000 service workers from Marriot hotels in eight cities walked off the job until the company ratified a new contract in December including pay raises and enhanced security measures to prevent sexual harassment and assault.
“So many workers and retirees — in the airline industry, the auto industry, the steel industry, to name just a few — have lost their pensions through bankruptcy over the last couple of decades,” Goldstein said. “Here, we preserved everything.”
Advocates contesting Ohio nuclear plant subsidies missed the deadline on Monday for gathering enough signatures to get their referendum to overturn House Bill 6 on the 2020 statewide ballot.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, released a statement blaming the organization’s shortfall on illegal tactics implemented by well-funded opposition groups and a 38-day delay in getting the petition approved for circulation.
“Nuclear bailout supporters of House Bill 6 have stooped to unprecedented and deceitful depths to stop Ohioans from exercising their Constitutional rights to put a bailout question on the ballot for voters to decide,” Pierce said. “We may never know how much money the corporate backers spent in their campaign of deceit, but we estimate their television, digital and radio advertising, direct mail and their blocking and fake petition to cost over $50 million.”
The Davis-Besse nuclear plant in northern Ohio | NRC
Pierce’s group led the campaign against HB 6 and began organizing petition efforts the same day Gov. Mike DeWine signed the legislation in July. It took 38 days, however, for the group to get approval from State Attorney General Dave Yost before they could start collecting the necessary 265,774 signatures — costing them more than a third of the 90-day deadline afforded to ballot petitions.
Pierce remains optimistic that the U.S. District Court for Southern Ohio will grant its request for an additional 38 days to gather signatures to make up for this “blackout period.” An evidentiary hearing is scheduled for Tuesday at which Judge Edmund Sargas Jr. could issue a bench ruling in the group’s favor. Sargas waived the preregistration requirement for petition circulators last week after the group successfully argued the state law violated free speech rights. (See Court WaivesOhio Preregistration Law.)
“We are fully prepared to continue circulating petitions if the court rules in our favor and grants us a full 90 days to collect signatures,” Pierce said.
FirstEnergy Solutions spokesperson Angela Pruitt told RTO Insider on Monday the company will resubmit deactivation notices for its Perry and Davis-Besse nuclear plants should Ohioans Against Corporate Bailouts succeed in their efforts.
FES rescinded deactivation notices for both facilities in July after the state approved HB 6 — which would funnel $150 million in ratepayer fees to the plants beginning in 2020 — but Pruitt says the ballot petition to overturn the law could reverse that decision, placing 4,300 jobs at risk. (See Ohio Approves Nuke Subsidy.)
“Unfortunately, any additional negative news from the courts or the successful submission of petitions to put a referendum on the ballot will destabilize the financial situation of those plants,” she said. “This will force the company to move back on a path to deactivation if alternative measures to provide needed financial support do not arise quickly.”
VALLEY FORGE, Pa. — PJM’s Operating Committee put manual revisions for its gas contingency rules on the fast track to endorsement on Tuesday after approving the changes on the first read.
Chris Pilong, PJM director of dispatch, told members old gas contingency procedures will be deleted from Manual 3 Section 5 and changes in Manual 13 Section 3.9 will remove references to PJM-directed precontingency fuel switching. Instead, the RTO will “discuss” any threats to fuel supply with the generator and request notification should that generator voluntarily decide to take any precontingency action to mitigate those risks.
The subtle language change signals a victory for generators who repeatedly expressed concern about PJM’s authority to direct pipeline switches — particularly after its revised gas contingency filing significantly redefined how resources can seek cost recovery after-the-fact. (See PJM Stakeholders: Gas Contingency Filing ‘Too Vague.’)
PJM will seek endorsement from the Markets and Reliability Committee on Oct. 31, with a scheduled effective date of Nov. 1.
PJM’s second analysis of resources that provide primary frequency response (PFR) looked a lot like its first — low participation across the board. (See “First Primary Frequency Response Evaluation Reveals Low Participation” in PJM OC Briefs: June 11, 2019.)
PFR is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.
PJM said 583 units with capacities of 50 MW or greater were evaluated for PFR across 10 events between March and September. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-mHz deadband, frequency stays outside the +/- 40-mHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 mHz.
No more than 28 units provided PFR during any of the selected events. In some cases, no units responded. PJM said most critical load and black start units evaluated did not provide PFR because many were offline, operating at maximum capacity or had inconclusive results.
PJM will continue outreach to generators to better understand the low participation rates. A final analysis will be presented to the OC in January.
Winter Weekly Reserve Target
PJM’s weekly winter reserve targets for 2019 remain unchanged from last year.
The targets — part of the reserve requirement study — help the Operations Department coordinate planned generator maintenance scheduling during the winter and cover against uncertainties associated with load and forced outages.
PJM also sets a 0% goal for its loss of load expectation (LOLE) in the winter, preferring instead to expect higher LOLEs throughout the summer. The 2019 targets for December, January and February are 22%, 28% and 24%, respectively.
The OC will endorse the targets at its November meeting.
PJM’s day-ahead scheduling reserve requirement decreased slightly from 5.29% to 5.12%.
The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations.
PJM will seek endorsement for the change at the November MRC and implement the new requirement in Manual 13 revisions.
PJM/NYISO Operational Base Flow Set to Zero
PJM and NYISO agreed to set an operational base flow (OBF) that once provided flexibility between the systems down to zero by month’s end.
The OBF, established in May 2017, carried a 400-MW limit and managed power flows over the Waldwick and ABC phase angle regulators (PARs) to account for natural system flows over the JK and ABC interfaces. PARs are power system transformers that have tap changing capability and can change the phase angle across the transformer and thereby increase or decrease power flow.
Outages on the Hudson-Farragut and Marion-Farragut lines resulted in a decreased limit of just 100 MW as of January 2018. PJM said on Tuesday both systems agreed to set the limit to zero at 11:59 p.m. on Oct. 31.
AUSTIN, Texas — The 20th anniversary of the landmark law that deregulated ERCOT’s market and paved the way for electric competition provided the theme for this year’s Gulf Coast Power Association fall conference Oct. 15-16.
In keeping with the idea that everything’s bigger in Texas, the GCPA conference filled a supersized ballroom at the Hyatt Regency Austin with 650 attendees, many wearing cowboy boots with their suits and blazers. Some wore Stetsons.
In panels on the history of Senate Bill 7 and ERCOT’s restructuring under the law, utility executives called Texas’ wide-open energy landscape the “greatest market in the world,” where some 200 retail electric providers (REPs) compete for customers.
“That’s the ERCOT miracle,” Mauricio Gutierrez, CEO of NRG Energy, said on a panel of chief executives from ERCOT’s three largest power producers. The panel included Thad Hill of Calpine and Curt Morgan of Vistra Energy.
Texas remains an independent republic when it comes to energy, panelists said.
The ERCOT market is the most deregulated in the U.S., they noted. Its transmission grid is largely separate from the rest of the nation’s high-voltage lines and therefore not regulated by FERC, they repeatedly pointed out. And ERCOT is a unique energy-only market, more like Australia than its U.S. counterparts, speakers said proudly.
In ERCOT, consumers pay only for the generation they need. They don’t pay to place additional generation on standby to ensure longer-term reliability, as do the organized capacity markets that serve much of the U.S. That can cause reliability challenges, especially during Texas summers, panelists acknowledged. (See Magness, Walker to Explain ERCOT Reliability to NERC.)
Nevertheless, supporters contended the ERCOT market provides the greatest benefits of any organized market in the nation — or perhaps even the world — for consumers and utilities alike.
“To me, this is the market that should be an example, not just to this country, but to many other countries,” Gutierrez said.
A panel of big-money investors, however, expressed skepticism about risking their funds in the Lone Star State, where volatile prices, often based on weather and resource adequacy, create an unpredictable environment.
Denise Persau Tait, president of Starwood Infrastructure Finance, based in Stamford, Conn., said her firm has a $2 billion to $2.5 billion “book” of energy investments in the U.S., but with less than 7% of it in Texas. The intense competition and low margins in ERCOT mean Texas is not a good bet, she said.
Only peak prices, fueled by heavy air conditioning use during Texas’ notoriously hot and humid summers, can guarantee an ample return on investment, but even those profits can be wiped out by milder weather, Persau Tait and other investors on the panel said.
For instance, June and July were not as hot as expected, keeping electricity prices down, while part of August was so hot it drove prices to ERCOT’s maximum of $9,000/MWh and triggered fears of rolling blackouts. (See ERCOT Survives Another Day in the Roaster.)
Starwood has no investments in Texas’ thermal generation, partly because of such unpredictability, Tait said.
“The issue that we’ve had anytime we’ve looked at deals in thermal generation in ERCOT has been volatility in the revenue streams and not being able to underwrite those deals,” she said. The fast-growing solar market in Texas is better, but “we don’t like to invest in deals where you’re relying on the weather.”
A panel on SB 7, passed in 1999, kicked off the conference with a look-back at efforts to deregulate ERCOT.
Those efforts began in 1995 with a bill to promote competition in the wholesale market, but things really got moving when SB 7 unbundled ERCOT’s vertically integrated utilities into generators, retail providers and operators of transmission and distribution systems. Municipal utilities and electric cooperatives were exempted from the bill but allowed to opt in to the market.
Steve Wolens, a longtime member of the Texas House of Representatives and the bill’s drafter and main proponent, shepherded its journey through the Legislature’s lower house. Policymakers at the time knew of deregulation failures in banking, airlines and telecommunications and didn’t want to repeat mistakes, so they went out of their way to get it right, he said.
“What we decided is that to deregulate, we had to worry about predatory pricing,” Wolens said. “How would we deregulate and not undergo predatory pricing so that the little guys could be run out of business?”
Texas lawmakers traveled to other deregulated states, including California and Pennsylvania, both of which began deregulating in 1996, to educate themselves.
“They went to California to find out how not to do a lot of things,” said John Fainter, former president of the Association of Electric Companies of Texas, which represented regulated utilities at the time. “They went to Pennsylvania and had some things that they learned how to do. ‘Price to beat’ [a major component of SB 7] was one of them.”
“Price to beat” helped small utilities gain a foothold in Texas’ freewheeling electricity market. It created a price floor below which established utilities couldn’t go to get rid of upstart competitors. New retailers, however, could set their prices lower than the price to beat.
Wolens said it may have seemed counterintuitive, but it worked.
“It’s not logical to say, ‘We’re going to deregulate, but we’re going to keep the price high,’ and nonetheless that is what we did,” he said.
When SB 7 took effect in 2002, “price to beat” led to a rapid increase of REPs, creating robust competition and lowering prices for consumers, he said.
A study published in January by researchers at Rice University concluded competitive markets in Texas had retail prices that corresponded more closely with wholesale costs and were generally lower than in markets where the state’s municipal utilities and electric cooperatives continued to operate non-competitive markets.
‘Everybody Signed It’
Wolens said the legislative process around SB 7 was successful because it included a broad range of stakeholders, with 27 people at the negotiating table representing investor-owned utilities, environmental groups, consumer advocates and others.
Each had something they wanted and something they feared losing, he said. The bill provided opportunities to profit from deregulation, but also included increases in renewable portfolio standards and financial support for low-income customers.
“None of these things would have passed as separate bills,” Wolens said. “It took putting together this 200-page bill like a Rubik’s cube so that everything fit together,” Wolens told the GCPA audience. “There was something in there for everybody to like and something in there for everybody to dislike.”
Wolens said he made it clear the bill wouldn’t pass if those who’d agreed to the deal later tried to alter it with legislative amendments. They all had to sign a piece of paper accepting the entire package.
“Everybody signed it — most of us in blood,” Fainter said. “Some of us were accused of not having any blood.”
The bill passed in the House, 145-4, and by an equally large margin in the Senate. It’s remained on the books with few changes for 20 years, standing the test of time, Fainter said.
Troy Fraser, a Texas senator at the time of the bill’s passage, said SB 7 worked because “It wasn’t [written] in the old proverbial smoke-filled room, in the back with no one else [present]. We had all the participants. Everyone knew what was going on. Everyone signed off.”
The bill provided for ERCOT’s board to include 25 members representing the diverse constituencies that negotiated SB 7. Some worried a governing board so large would be unwieldly, but it worked perfectly at the time, Wolens said. Later, the size of ERCOT’s board was cut to 14, where it stands today, he noted.
As the panel wrapped up, Fraser, who described himself as a conservative Republican, told Wolens, a Democrat: “That diversification you put on the board gave us the feeling that the fox was not guarding the henhouse. We had a very diversified board making sure everyone was treated fairly.”
ERCOT’s Job Performance
ERCOT’s role managing its deregulated market got a once-over during a panel moderated by Brad Jones, former CEO of NYISO and chief operating officer of ERCOT. Jones, who said he’s retired, now serves as an advisory member of the GCPA board.
With some knowing encouragement from Jones, panelists jumped on the “Texas-is-best” bandwagon.
Eric Schubert, director of U.S. regulatory affairs for BP Energy, said SB 7 meant FERC doesn’t regulate ERCOT, and that’s proven beneficial.
“FERC’s great,” Schubert said, eliciting chuckles from the audience. “But the fact is that, again, Texans had the ability to negotiate with Texans. They didn’t have to worry about other states. They didn’t have to worry about federal jurisdiction. That simplified matters quite a bit in terms of the development of the ERCOT market.”
It also made it easier to build the $7 billion Competitive Renewable Energy Zones (CREZ) transmission project, he said, bringing wind power from the Texas panhandle and West Texas to the population centers of Dallas, Austin and other cities. CREZ resulted in the construction of 2,400 miles of high-voltage lines, capable of carrying 18.5 GW of West Texas wind to ERCOT’s major load centers. (See Overheard at Infocast’s Texas Renewable Energy Summit.)
ERCOT’s energy-only market has been better at integrating new technologies and renewables than systems with more layers of regulation, Schubert said.
Clifton Karnei, general manager of the Brazos Electric Cooperative and a longtime ERCOT board member, said Texas has a robust grid because of SB 7. The “postage stamp” transmission rates in Texas means everyone pays the same price for transmission access, he noted.
Kenny Mercado, chief integration officer at CenterPoint Energy and an ERCOT board member, said Texas is delivering cleaner, more reliable electricity than ever before.
“We have got it right in almost every aspect today,” Mercado said. “ERCOT has been the critical link to our success over the journey. I’ve learned from the inside out how important the role of ERCOT is. They see everything in real time. They see the electron in real time. They see the dollar in real time. They understand the current state of our market. And they understand the future needs and the future responsibilities.”
Scott Hudson, senior vice president of Vistra Energy and president of its retail business added, “This is the best market to work in in the world.”
Reliability Challenges Ahead
After all the accolades were over, Jones asked about the downsides of SB 7.
Karnei said the long-term sustainability of ERCOT’S energy-only market remains in question. “I think the jury is still out on that,” he said.
Karnei said he calls ERCOT a “casino market.” Some years are great for energy providers; others aren’t. It’s like pulling on the handle of a slot machine. You win some, you lose some, he said.
The future of thermal generation, in which coal and natural gas plants convert heat to energy, is especially problematic, he said. Older plants are being retired and new ones aren’t getting built, panelists said. (See NERC: ERCOT, CAISOFace Summer Reliability Concerns.)
Bill Berg, vice president of wholesale market development at Exelon Corp., said consumers benefit from lower prices in ERCOT, but investment is needed that will increase costs. Otherwise, summer reliability will be at risk.
“It should be an exciting time for the next couple of summers,” he said.
SAN FRANCISCO – Even promoters of renewable energy are starting to worry about reliability as fossil-fuel plants retire and dispatchable renewable resources are slow to take their place.
At the American Council on Renewable Energy’s Renewable Grid Forum on Thursday, speakers talked about the need to replace gas peaker plants with batteries or other resources that can ramp up quickly on demand. Some floated the idea of installing battery storage at natural gas plants to have an instant-on solution to meet peak load. It would be less polluting, at least until the batteries ran out and the gas kicked in, they said.
About 75 people attended the event at a Hilton hotel adjacent to San Francisco’s Chinatown and just down the street from the Transamerica Pyramid.
Big utilities have joined the push for renewables, and some utility executives spoke at the meeting.
During one panel on the role of utilities in the transition to renewable energy, Frank Prager, with Xcel Energy, said the company committed in December to carbon-free energy — the first large utility to do so — but is still trying to figure out how to get there by its stated goal of 2050.
Xcel is likely to obtain an 80% reduction in carbon emissions by 2030, but then costs go through the roof, Prager said. The last 20% will be the hardest to achieve, he said.
Because wind and solar production tends to be seasonal, “you’d have to store terawatt-hours of energy for months at a time,” and that would cost trillions of dollars, he said.
Older technology such as pumped hydro could help. So could advanced nuclear generation, he said. Some developers are working on nuclear units that are much smaller than traditional plants. (See West Wrestles with Resource Adequacy, Grid Reliability.)
Excess energy might be used to create hydrogen that could then be pumped through natural gas pipelines. Fossil fuel with carbon capture and sequestration is another possibility, albeit an expensive one, he said.
Or “Mr. Fusion could come to the fore,” he said, a joking reference to the movie “Back to the Future Part II.”
Federally funded research into new technologies is needed for the nation to totally eliminate carbon emissions from electricity production, Prager and others said.
In the meantime, more utilities are joining the states and cities that have vowed to go all-green. Duke Energy, one of the nation’s largest power producers, pledged in September to go carbon-free by 2050. And PacifiCorp, another energy giant, said last week it planned by 2030 to cut its carbon emissions by 60% below 2005 levels.
“At PacifiCorp, we share a bold vision with our customers for a future where energy is delivered affordably, reliably and without greenhouse gas emissions,” the company said in a statement posted on its website.
Atlanta-based Southern Co. said in April it planned to go low-to-no carbon by 2050. NextEra Energy, which owns Florida Power and Light, said in June it would reduce carbon emissions by 40% from 2005 levels by 2025. And DTE Energy, a Detroit-based company, said in September it would seek to achieve net-zero-carbon emissions by 2050.
Julia Hamm, CEO of the Smart Electric Power Alliance (SEPA), a group that advocates for carbon-free energy by 2050, said much of the movement toward cleaner energy sources is being driven by cost; renewables, including wind and solar, are among the cheapest forms of energy available now.
But Xcel still deserves credit for its “big, bold commitment,” which prompted other energy companies to jump on the carbon-free bandwagon, she said.
“Since Xcel’s announcement last year,” Hamm said, “the announcements from utilities are coming fast and furious.”
It remains to be seen, however, whether they can meet those commitments.
FERC rejected for a third time a bid by developers to obtain transmission status and cost-based rates for a proposed $2 billion pumped storage project in CAISO (EL19-81.)
The commission dismissed Nevada Hydro’s complaint that CAISO failed to follow its Tariff in studying the Lake Elsinore Advanced Pumped Storage Project (LEAPS) in its transmission planning process.
LEAPS, which has been in development since the late 1990s, would be located about midway between Los Angeles and San Diego in Riverside County, with Lake Elsinore serving as the lower reservoir. Developers say it would produce 6,000 MWh daily, based on 12 hours of operation at the full plant capacity of 500 MW, serving the transmission systems of San Diego Gas & Electric and Southern California Edison.
In a 2008 order, FERC rejected LEAPS’ request to be treated as a transmission asset, saying it would not be appropriate to require that CAISO assume operational control of the project as requested (ER06-278).
Last year, the commission rejected the company’s request for a declaratory order finding that LEAPS is a transmission facility eligible for recovery of its costs through CAISO’s transmission access charge (TAC). The commission sided with CAISO and the California Public Utilities Commission, which had argued that Nevada Hydro’s petition was an end run around the ISO’s transmission planning process (EL18-131). (See FERC Tells LEAPS to Get in Line.)
As a result, Nevada Hydro submitted the project for CAISO’s 2018/19 transmission planning cycle. CAISO’s study of LEAPS was included in its final transmission plan on March 29, 2019, which concluded there was no need for any new transmission projects in Southern California, including LEAPS.
Illustration of proposed Lake Elsinore Advanced Pumped Storage Project | Nevada Hydro
Eight Overloads
Nevada Hydro submitted LEAPS as a transmission solution to eight thermal overloads that CAISO identified on the SDG&E system over CAISO’s 10-year planning horizon. But CAISO did not study it for those violations because the ISO had already decided on other solutions, including remedial action schemes and battery storage and demand response selected by the CPUC in its integrated resource planning (IRP) process.
Nevada Hydro complained that CAISO did not attribute any cost to the batteries, demand response or remedial action schemes, or compare them to the cost of LEAPS to determine which would be more cost-effective. CAISO said because those solutions were already in operation or under construction, they presented no new additional capital costs to consider.
Nevada Hydro also argued that CAISO failed to follow its Tariff requirements for evaluating LEAPS as an economic study request, underestimating its benefits.
The PUC; Six Cities (Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside); the California Municipal Utilities Association; NextEra Energy; and the California Department of Water Resources’ State Water Project opposed Nevada Hydro’s complaint and backed CAISO’s analysis. Opponents contended that LEAPS is primarily a generation facility whose costs should be recovered through market revenues rather than the TAC.
The company did not respond to a request for comment.
Lake Elsinore | City of Lake Elsinore
No Tx Need
In its ruling, the commission said CAISO’s analysis had followed its Tariff.
“Because CAISO’s studies found no need for new transmission solutions, and because the existing solutions present no new capital costs, we find that CAISO’s Tariff does not require it to compare the cost-effectiveness of LEAPS with that of reliability solutions that are already in operation or under construction, or discuss the pros and cons of relying on existing measures that adequately ensure reliability versus investing in new transmission assets,” FERC said.
“… We continue to find that CAISO’s transmission planning process is designed in a manner that considers the full benefits of any proposed transmission solution, and that CAISO applied its process correctly with respect to its study of LEAPS,” the commission added.
The commissioners also rejected Nevada Hydro’s complaint over CAISO’s use of 4,183 MW of generation and a 2,000 MW export limit identified in the CPUC “default scenario” portfolio, saying the company should have objected during the transmission planning process. “Once the planning assumptions and study plan are adopted, those assumptions are locked in for the rest of the transmission planning cycle,” FERC said.
“We find no merit in Nevada Hydro’s assertion that CAISO abdicated its responsibilities as a regional transmission organization by adopting the CPUC default scenario portfolio. As noted by CAISO, its role is transmission planning, not resource procurement, and nothing in its Tariff requires CAISO to second guess or reverse CPUC’s resource procurement decisions or dictate what resources CPUC-jurisdictional entities can or cannot procure.”
FERC Rejects Rehearing on CAISO Capacity Market
Also last week, FERC denied rehearing on its 2018 order rejecting a request to direct CAISO to develop a capacity market (EL18-177-001).
The request had been made by CXA La Paloma, the operator of a 1,124-MW gas-fired plant in Kern County, Calif. CXA La Paloma contended California’s lack of a centralized capacity procurement was unjust and unreasonable because of falling energy prices that undermined the finances of independent generators. (See FERC Rejects Request for CAISO Capacity Market.)
On rehearing, the commission dismissed contentions that it ignored evidence and misread the law in rejecting La Paloma’s complaint. It also rebuffed requests to conduct a technical conference to examine the state’s existing resource adequacy framework. “The record evidence did not persuade the commission that additional processes, other than those [stakeholder proceedings] noted in the complaint order that were already underway, were necessary.”
VALLEY FORGE, Pa. — PJM’s concerns over financial transmission right (FTR) underfunding on projects with incremental auction revenue rights (IARRs) won’t be addressed through any Operating Agreement revisions after all.
The Market Implementation Committee on Wednesday unanimously voted to close an issue charge examining how to manage the risk associated with customer-funded IARR projects at coordinated market-to-market flow gates. The decision means PJM will retain the status quo, with the option for stakeholders to revisit the issue in the future.
IARRs are created by the addition of required transmission enhancements, merchant transmission or customer-funded upgrades and are granted to the customer only if the improvement provides additional capacity that makes the request feasible. PJM guarantees that awarded IARRs are at least 80% of studied IARR megawatts.
Brian Chmielewski, PJM’s manager of market simulation, said underfunding of interregional IARRs could occur because MISO’s rules cannot guarantee future firm flow entitlements (FFEs) to PJM for upgrades built for IARR requests. Any portion of the FFEs for an affected coordinated flowgate that is less than 80% of the IARR megawatt total will result in inadequate FTR revenues, the RTO has found.
Chmielewski said staff and stakeholders considered amending the OA to remove the guarantee of 80% of originally awarded IARRs if MISO facilities are impacted and future FFEs cannot support the request once the project is in service. Another option — to no longer allocate IARRs that would impact market-to-market facilities — was also considered.
In the end, staff recommended that PJM maintain the status quo and instead enhance coordination with MISO on preliminary upgrade determinations to better reduce risk.
New ARR/FTR Task Force
Stakeholders approved a new task force that will evaluate the risks and rewards structural changes to the FTR market after rejecting Monitoring Analytics’ narrower proposal to review the mismatched allocation of congestion rights.
The endorsed plan — sponsored by Dominion Energy, Exelon, NextEra Power Marketing, PSEG Energy Resources & Trade, Dynegy Marketing & Trade, and Vitol, and the Financial Marketers Coalition — creates a task force that will explore both technical and policy issues in the FTR market in the wake of the GreenHat Energy default. The MIC voted 213-1 in favor of the issue charge, with 33 abstaining. (See related story, No Fireworks at Conference on PJM FTR Settlement.)
Mike Borgatti of Gabel Associates said the issue charge ensures a broader scope for discussion and doesn’t presuppose any specific solution — something its sponsors felt was lacking in the plan Monitoring Analytics presented last month. (See “Monitor: Review ARR/FTRs to Improve the Allocation of Congestion Rights,” PJM MIC Briefs: Sept. 11, 2019.)
“There is some fundamental language that the Market Monitor used that we can’t get consensus on,” Borgatti said. “We wanted to ensure that we weren’t writing this in a way that it was conclusive to a certain solution.”
Joe Bowring, PJM’s Independent Market Monitor, defended the specificity of his issue charge and argued the alternative is too vaguely worded.
“Being specific is apparently now a pejorative,” he said. “Our concern is [if] there is no issue defined it’s not clear how we get to solving” it.
Last month, the Monitor told the MIC that the existing constructs for auction revenue rights and FTRs leaves some load zones unable to completely offset their congestion costs.
Stakeholders agreed the issue should be addressed, but through a broader review of FTR/ARR design, as suggested in the independent GreenHat report released in March. Monitoring Analytics maintained that the key work activities in their issue charge allowed for a broader review of the market. It would require stakeholders to identify the causes of congestion misalignment and decide whether changes to the market design could fix the problem, the Monitor said.
Stakeholders weren’t convinced. The approved issue charge will explore the history and evolution of the ARR/FTR market design, including its FERC-approved objectives, how it compares to other regions and its value proposition for members. The new task force will assemble in January and meet once a month over the course of a year.
Winter Extended Tx Outages
PPL’s Breinigsville-Alburtis 500-kV line will experience extended outages this winter while undergoing a second round of upgrades to address aging infrastructure and operational inflexibility.
The TO submitted an outage ticket from Nov. 18 until June 12, 2020, while it works to rebuild the existing 500-kV line and add a second. The work was scheduled for the winter months when peak loads are lower. PJM said the outages may require generation redispatch to address voltage or stability issues.
The company said it would be able to recall the line within 72 hours between Jan. 1 and March 1 if needed for reliability.
Extended outage scheduled for the Breinigsville-Alburtis 500 kV line. | PJM
The changes, endorsed at the Markets and Reliability Committee in April, require existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will become able to satisfy CP requirements or forfeit its capacity interconnection rights. Resources would be granted exceptions for no more than two auctions. (See Load Interests Endorse PJM-IMM Must-offer Proposal.)
PJM will update Sections 5.2, 5.4.1, 5.4.7 and 8.8 in Manual 18 to reflect these changes. MIC and MRC endorsement is scheduled for November.
Manual 15 Clarifications on VOM Costs
PJM offered a first read of Manual 15 revisions that clarify that market sellers can only change the format of maintenance adders — such as $/MMBtu, $/MWh or $/start — during the annual review period for energy offer components.
Staff will add Section 2.6: Variable Maintenance Costs to reflect this after promising to do so in the proceedings for ER19-210, PJM’s filing to include variable operations and maintenance costs in energy offers. FERC partially accepted the RTO’s Tariff revisions in April but asked for more clarity on what maintenance costs sellers can include in their energy market offers. (See FERC to PJM: Clarify Allowable Costs for Energy Offers.) FERC accepted that compliance filing in August.
PJM will seek endorsement from the MIC next month, the MRC in December and from the Members Committee and Board of Managers in January.
LITTLE ROCK, Ark. — SPP members moved last week to eliminate Z2 revenue credits for sponsored transmission upgrades, the source of years of stakeholder frustrations and jokes.
The Markets and Operations Policy Committee unanimously endorsed a Regional Tariff Working Group revision request (RR) that eliminates Z2 credits and replaces them with incremental long-term congestion rights (ILTCRs), effective February 2020.
MOPC first overrode pushback from members seeking to delay RTWG RR374’s implementation, contingent on fully developing ILTCRs, rejecting the motion against seven “no” votes and seven abstentions. That would have allowed additional upgrades to be granted Z2 credits during the delay.
“One more sponsored upgrade that qualifies for Z2 credits is one too many, in our opinion,” said Oklahoma Gas & Electric’s Greg McAuley.
Under Attachment Z2 of SPP’s Tariff, sponsors that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. Multiple stakeholder teams have taken a crack at improving the process, which, combined with software problems, has delayed credits to transmission customers.
Dan Simon, outside counsel for the EDF Renewables, warned RR374 doesn’t comply with FERC’s policies on interconnections (Order 2003) and long-term firm transmission rights (Order 681). To eliminate Z2 credits, he said, the commission would have to find SPP’s ILTCR rules comply with both policies.
Simon said Order 2003 allows ISOs and RTOs to directly assign upgrade costs if, in return, they receive rights that are valuable, well-defined and tradeable. By modifying ILTCR rules to limit total compensation to each upgrade’s directly assigned costs plus interest, RR374 will make the ILTCR rules non-compliant with Order 681, he said.
“If you want to go ahead and vote in favor of the Z2 credits’ elimination, it shouldn’t be filed with FERC,” he said. “It shouldn’t be effective until you develop and modify ILTCR rules to where they have some actual value. I think this will be heavily contested [at FERC].”
“We don’t know when this thing will be done to everyone’s satisfaction,” McAuley said. “It could be a quarter; it could be four years. Once you agree to Z2 credits, they’re permanent.”
“We’re tired of paying for things that have no benefit for the customers because we adopted such a complicated process,” Southwestern Public Service’s Bill Grant said. “We’re funding 80% of creditable upgrades, which was not our intention.”
The Tariff change is one of the first Holistic Integrated Tariff Team recommendations to be endorsed, following the approval of its 21 proposals to integrate the expansion of renewable energy, boost reliability and improve transmission planning and the wholesale market. (See SPP Board Approves HITT’s Recommendations.)
MOPC Approves $336 ITP Portfolio
MOPC approved the 2019 Integrated Transmission Planning 10-year assessment, a 27-month process resulting in 44 transmission projects with a total engineering and construction cost of $336 million. The portfolio, which includes 166 miles of new EHV transmission and 28 miles of rebuilt HV infrastructure, will address 145 system issues, the Economic Studies Working Group said.
SPP projects the assessment will provide a 40-year benefit-to-cost ratio of between 3.5 to 1 and 5.8 to 1, with residential customers seeing a savings of $0.04-$0.23/kWh on the average bill. Approximately 75% of the portfolio encompasses regional highway projects.
“We’re trying to evaluate whether or not the delivery [of low-cost generation] can reduce the cost to load on the SPP network,” said SPP System Planning Director Antoine Lucas. “To the extent we are unable to justify [capital] investments that have less costs than the savings to load, we think we will see projects that wouldn’t be justified. We’re saving fuel costs for load in SPP, albeit at a capital cost in transmission. We see that as a net benefit to customers.”
ESWG Chair Alan Myers, with ITC Holdings, said the assessment addresses overlapping top-ranked economic needs and reliability concerns, along with seams impacts, congestion, stability concerns and operational issues. The projects are expected to pay for themselves in less than 20 years, with customers seeing benefits in under two years.
McAuley, saying OG&E sees a “mismatch on the commitment side,” warned about the consequences of continuing to connect renewable generation that “far exceeds the needs of our customers.” SPP’s reserve margin sits in the mid-20% range, with more generation in the interconnection queue than the RTO “knows what to do with.”
“OG&E will be advancing this position much more aggressively in the future, not because we hit a wall today, but because we see a wall coming,” he said. “How do we impact the rest of the generation that’s already there? SPP will have an optics problem when we have a lot of renewable generation on the ground and we can’t get it to the load. Who is going to feel that pressure? Who is going to be asked to pay for that transmission to get that generation to load?”
Myers said a “significant” amount of “non-committed generation” is included in the model, “but we’ve also taken great care to make sure we’re not over-planning.”
“If the wind is there, the failure to plan for it only exacerbates the problem,” he said. “We’ve taken a number of steps to carve out commitments not tied to SPP load.”
MOPC Chair Holly Carias, with NextEra Energy Resources, relied on SPP’s new web-based voting system (see below) to vote on the ESWG’s motion. Transmission owners and transmission users both favored the ITP assessment, by 13-5 and 42-7 votes, respectively, easily clearing SPP’s 67% threshold.
Separately, MOPC also approved a revision request that adds a high-wind dispatch for the powerflow model’s sensitivity cases that measure stress on the grid. The Transmission Working Group recommended TWG RR379’s approval, saying the additional flexibility will enable SPP to demonstrate its proactive approach to continuous improvement during NERC audits for TPL-001-4.
The motion passed with three no votes and three abstentions.
Members Endorse Quick-Start Revision
Members approved a Tariff revision that complies with FERC’s directive to allow fast-start resources to set clearing prices, despite stakeholder and Market Monitoring Unit opposition.
SPP staff said MWG RR375 was limited in scope to meet only FERC’s requirements. The commission in June found the grid operator’s quick-start pricing practices to be unjust and unreasonable because they don’t allow prices to reflect the marginal cost of serving load and directed the RTO to make six Tariff changes in response. (See FERC Orders Fast-start Rules for SPP.)
Staff said they believe the proposed protocol and Tariff changes comply with FERC’s order and minimize the amount of changes, staff time and vendor expenditures needed to address the order.
The MMU disagreed, saying it had significant concerns with the proposal and it would file comments at FERC noting its objections and concerns. The Monitor said the commission requires separate market solutions for dispatch and pricing and to maintain a cost-minimizing dispatch solution that would separate price from quantity in the market.
MMU Supervisor John Luallen said RR375 only mitigates the pricing run and start-up and no-load offers can be modified after commitment and used to set price.
“By separating price and quantity, you will end up with an inconsistent price for quantity,” Luallen said. “FERC was very specific about how certain things are to be done in this order.”
Golden Spread Electric Cooperative and City Utilities of Springfield (Mo.) filed comments opposing the proposal. Golden Spread said the RR “does not allow prices to reflect the cost of quickly responding resources from an offline state, which will not allow [quick-start resources] dispatchable from zero to set price in the same way that other dispatchable resources set price, and hence will not reflect the QSR cost of or value of responding quickly to unforeseen system needs.”
The cooperative was among six members to oppose the revision. Four others abstained from the vote.
The MWG withdrew four other revision requests as a result of MWG RR375: RR116, RR137, RR142 and RR256.
Members also endorsed MWG RR361, which creates ramp-capability up and down products designed to pre-position resources with that capability to manage net load variations and uncertainties and to provide transparent price signals to incent resource flexibility and economic investment.
The revision was opposed by seven members, with two abstaining.
“For some of you old guys that used to run [balancing authorities],” American Electric Power’s Richard Ross, chair of the MWG, began before catching himself. “For some of you more seasoned operators, back in the old days, we would recognize that when the morning load pickup came, you had to get those units ready to move. You might hold one of those units back a little back so you can ramp and have ramping capability.”
SPS’ Grant agreed with the need for ramping products but questioned the reliability of short-term forecasts to determine renewable energy’s availability.
“Weather can change rapidly at the resource,” SPP’s Gary Cate said. He said in their analysis, staff used 36 operating days and re-ran more than 18 different scenarios, resulting in 684 day-ahead market and reliability unit commitment reruns and 197,000 real-time market reruns.
“In only five cases did the solar or wind farm clear ramp capability up,” Cate said.
The MMU said it supports RR375 after many of its concerns were addressed during its development. However, the Monitor plans to file with FERC over lingering issues, including a lack of transparency on the confidence level used to establish ramp requirements and the lack of a claw-back provision should a resource not perform.
Change Continues GI Requests’ Processing
MOPC easily approved a Business Practice Working Group RR documenting a change to generator interconnection modeling assumptions.
BPWG RR370 changes the assumptions to stop artificially forcing wind and solar on at 10% in remote areas in the off-peak case and reduces the amount of existing firm generation that must be offset to accommodate new study generation. The change, recommended by the GI improvement task force as a short-term step that allows new requests to be processed, enables the study process to accommodate larger cluster sizes.
The change is seen as a patch until a new group, the NRIS, ERIS (network resources/energy resources interconnection service) and Deliverability Task Force, can develop a longer-term solution. In the meantime, staff continues to struggle with a GI queue clogged with study requests.
“We’ve got to work our way through the queue, no question about it,” said Midwest Energy’s Bill Dowling. “We have to be sure we’re thorough about it. The [change] is intended to give us a way to complete the studies. It keeps the ball rolling.”
It’s a briefing McKinnie has delivered in several venues recently.
“And you’ll get it again at the [Regional State Committee] meeting,” McKinnie said, referring to the RSC’s Oct. 28 meeting in Little Rock.
A committee of RSC members and their Organization of MISO States’ (OMS) counterparts have commissioned the grid operators’ market monitors and Potomac Economics to gather stakeholder feedback as part of the analysis on the interregional processes.
One comment in particular has “raised eyebrows,” McKinnie said.
MISO member Entergy charged that SPP’s failure to conduct economic planning since 2016 has resulted in continual congestion on the Neosho-Riverton flowgate in Kansas. Market-to-market (M2M) settlements on the flowgate had reached $29.3 million in SPP’s favor through July since 2015, accounting for almost half of the $64.3 million it has accrued from MISO since the M2M process began.
“Had SPP performed an economic plan during that time, it is possible that SPP might have found a solution (and started construction) to fully address the … congestion,” Entergy said. “If an RTO is not conducting an economic plan during the planning period, the RTO should provide a well-supported explanation to stakeholders.”
SPP and MISO skipped their biennial coordinated system plan (CSP) study last year to refine their interregional process, which has yet to result in a joint project. SPP did include an economic analysis in the 2019 CSP, which, like its two predecessors, failed to identify a joint project.
“Both SPP and MISO should focus on improving their regional processes rather than increasing the already substantial time and energy each RTO spends on interregional issues,” Entergy said.
McKinnie said Entergy’s comments are likely to be part of the discussion when the OMS meets on Oct. 24.
The RSC-OMS Liaison Committee has requested two rounds of analysis. The market monitors and Potomac Economics have split up the first round of studies, which are focused on rate pancaking and unreserved transmission use charges, the M2M process and joint dispatch.
Keith Collins, executive director of SPP’s MMU, told members that the Monitor has found little evidence of pancaking on the seam, but some SPP entities have been charged for unreserved transmission use on the MISO side. The MMU expects to publish its report in November.
The Liaison Committee will have to replace Missouri Public Service Commissioner Daniel Hall when his term expires in November, McKinnie said. Hall also leads the OMS half of the committee.
SPP Uses Web-based Voting System
SPP stepped boldly into the 21st century by introducing a web-based voting system developed by a third party. The eBallot software replaces roll call voice votes, which can take up to 15 minutes at MOPC, given the group’s 82 voting members.
“That could add up to quite a bit of time in meetings where there are multiple votes,” said SPP spokesman Derek Wingfield.
Results of SPP’s first eBallot vote | SPP
He said eBallot improves the integrity of the voting process and reduces the chance for human error in counting the votes. Voting members log in to a secure system where they cast and certify their votes. A report is then generated that calculates whether motions pass or fail based on the averages of the transmission owners’ and users’ approval percentages.
The system was used to approve the 2019 ITP assessment’s report.
“We do not have any indications that the Russians tampered with this,” Chair Carias said in announcing the final tally.
RTWG Chair Kays Announces Retirement
Last week’s meeting marked David Kays’ last appearance before MOPC. Kays recently announced he will retire from OG&E at the end of the year after 21 years with the utility.
Kays became active with SPP in 2004, joining the RTWG two years later and serving as its chair and vice chair for eight years. He will still lead three more RTWG meetings before handing over “the scepter of power,” an aluminum softball bat, to his successor.
Following the committee’s decision favoring the elimination of Z2 credits — eventually — Kays cracked, “I’ve now seen the birth and death of Z2 revenue credits in my career.”
OG&E’s McAuley, who announced the “sad news” to MOPC, said, “We’re really going miss that guy. He is a very significant contributor to both SPP and OG&E.”
SPP Halts Consolidation of Working Groups
The consolidation of working groups has been paused in order to do more analysis, brainstorming and creative thinking “as if we were redesigning the MOPC organization from scratch,” said the committee’s staff secretary, Senior Vice President Lanny Nickell. (See “SPP Stakeholders React to Proposed Working Group Consolidation,” MOPC Briefs: July 16-17, 2019.)
Nickell said he, Carias, SPP Board of Directors Chair Larry Altenbaumer and MOPC Vice Chair Denise Buffington will be working together on a consolidation business case to be shared with members. The group hopes to have a new organizational structure in place by May 2021.
In the meantime, SPP has already moved the Balancing Authority Operating Committee and its responsibilities into the Operating Reliability Working Group.
“It was an incremental change we felt was worth doing,” Nickell said.
COO Carl Monroe, who has been overseeing a survey of behind-the-meter resources, said staff will propose a policy for the proper treatment of BTM resources and load. The white paper will also include energy storage resources, the subject of FERC’s Order 841. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
Consent Agenda Clears RRs, Baseline Resets
The committee unanimously passed the consent agenda, which included the annual violation relaxation limits analysis, a sponsored upgrade study, a pair of baseline resets for approved projects, nine revision requests and scope changes for 12 stakeholder groups.
Staff recommended an approval of APEX Clean Energy’s upgrade to the Neosho–Caney River 345-kV line in Kansas, scheduled to go in service next year.
The Project Cost Working Group recommended both baseline resets:
Evergy’s $54.1 million update for a 345/138-kV transformer and 138-kV transmission line project, estimated at $67.1 million in 2017.
Evergy’s $34.4 million update for network upgrades on a 138-kV circuit, which was originally projected to cost $58.3 million.
The approved RRs included:
BPWG RR372: Documents the practices to evaluate energy storage resources in the interconnection queue.
BPWG RR378: Clarifies the detailed project proposal’s (DPP) data-validation process by limiting the number of times a submitter can correct data errors, allowing staff more time to assess the projects.
ESWG RR367: Revises the Integrated Transmission Planning Process (ITP) manual to incorporate separate, optional load forecasts into the ITP conventional resource plan.
RTWG RR366: Ensures TOs consistently account for point-to-point (PTP) revenue by eliminating overpayments to customers when TOs don’t reduce their annual transmission revenue requirement with PTP revenue.
RTWG RR381: Revises Tariff language to indicate transmission invoices may also include adjustments for prior services furnished under the Tariff.
TWG RR363: Defines existing transmission facilities’ “material modification” as being “based on engineering judgment” in NERC’s facility interconnection studies (FAC-002) compliance.
TWG RR364: Reduces the planning criteria’s language on equipment rating, which is already covered by NERC Reliability Standard FAC-008.
TWG RR368: Clarifies how local planning criteria will be considered in ITP studies.
TWG RR384: Clarifies the ITP manual to better meet compliance with firm transmission service modeling requirements for planned retirements of generator resources in the base reliability models.
NextEra Energy touted “one of the best renewable development periods” in its history as it reported third-quarter adjusted earnings on Tuesday, beating analysts’ expectations.
The Florida-based company’s earnings were $1.16 billion ($2.39/share), an increase over 2018’s third-quarter earnings of $1.04 billion ($2.17/share). Zacks Consensus Estimate had projected earnings of $2.27/share.
Speaking with analysts Tuesday, CFO Rebecca Kujawa said NextEra has increased year-to-date adjusted earnings by nearly 12%, compared to the same period in 2018. NextEra Energy Resources drove much of that growth, she said, pointing to a renewables backlog of more than 12.3 GW, more than the operating portfolio it had at the end of 2014, which took 15 years to build.
Energy Resources added 1,375 MW to its backlog in the last three months, Kujawa said. The company added 747 MW of solar and 340 MW of battery storage, all paired with new solar projects, she said, “as we further advance the next phase of renewables deployment that pairs low-cost wind and solar energy with a low-cost battery storage solution.”
Kujawa said NextEra removed 339 MW from MISO’s interconnection queue because of increased transmission upgrades and rising interconnection costs as developers have rushed to get projects approved as tax credits wind down. The “speed bump” only creates opportunities, she said.
| NextEra
“Some of those projects had some obvious customers that wanted to buy some wind and solar projects, which will create opportunities for Energy Resources … It also creates the opportunity or incentive for us to optimize our existing queue positions and existing interconnection rights to maximize all the generation that could be filled for those interconnection requests,” she said.
“Overall, we are pleased with the progress we are making at NextEra Energy,” CEO Jim Robo said in a statement. “I will be disappointed if we are not able to deliver growth at or near the top end of our [$10.00-10.75] adjusted earnings per share expectations range in 2022.”
On a GAAP basis, NextEra’s third-quarter income was $879 million ($1.81/share) compared to $1.01 billion ($2.10/share) a year ago. GAAP earnings considered the effects of the federal corporate tax reduction and non-qualifying hedges.
NextEra’s share price gained $2.87 following the earnings release, closing up 1.2% at $236.24/share.
LITTLE ROCK, Ark. — Google, the world’s ubiquitous search engine — “Google it!” — made its SPP membership official when it participated in October’s Markets and Operations Policy Committee.
The company, which signed a membership agreement in May, observed two MOPC meetings before casting its first vote on the consent agenda. Jeff Riles, Google’s lead for global infrastructure energy policy and markets, contributed to the stakeholders’ discussions when it centered on renewable energy and transmission costs.
Riles, an energy regulatory attorney formerly with Enel, represents Google under the Google Energy brand, which was created to reduce parent company Alphabet’s energy consumption and to produce and sell clean energy. Google joins Walmart as SPP’s only two end-use customer members. (See New SPP Member Walmart Eyes ‘Everyday Low Costs.’)
He said Google joined SPP because of the company’s energy procurement needs and plans to grow its businesses within SPP’s footprint.
“As a consumer, we recognize the benefits that wholesale, competitive power markets provide,” Riles said. “What’s happening here will impact our business. Google wants to follow market developments in SPP and have a voice in its future.”
Google leads SPP’s corporate buyers with 1,135 MW of purchase power agreements, almost quadruple that of T-Mobile and Facebook’s 320 MW apiece.
Riles noted Google has load and “pretty significant” renewable projects in SPP’s footprint. The corporation has already invested $2.4 billion in an Oklahoma data center, and it brokeground earlier this month on a $600 million data center in Nebraska with more load than the nearby city of Lincoln (excluding Cornhusker gamedays). The facility will be powered by 100% renewable energy when it is operational in two years.
In September, Google announced a 1,600-MW package of renewable deals across the U.S., Europe and Chile that it calls the largest corporate renewables purchase ever. The purchase will increase its total wind and solar agreements by more than 40%, the company said.
