Developers of six renewable projects totaling about 460 MW will start contract negotiations with New England states in the next phase of a multistate effort to procure clean energy.
Four of the projects will negotiate with three states: Connecticut, Rhode Island and Massachusetts; two projects will proceed with only Rhode Island and Massachusetts. The solicitation generated 24 responses from 30 developers, some in teams.
“Not all projects selected to advance to contract negotiation at this stage will necessarily obtain approved contracts, which may affect the total contracted megawatts resulting from this” request for proposals, the states said in announcing the selections.
The states said they expect to negotiate better power prices in combination than they would have if they acted alone.
Most of the generation would come from solar projects. The selected bidders are:
Ranger Solar, with five solar projects totaling 220 MW in Connecticut, Maine and New Hampshire;
Deepwater Wind’s 26-MW solar facility in Connecticut;
Ameresco’s 20-MW solar project, also in Connecticut;
Antrim Wind’s 26-MW wind project in New Hampshire;
EverPower’s 126-MW Cassadaga wind project in Chautauqua County in western New York; and
Two 20-MW solar projects from RES Americas, one in Connecticut and one in Rhode Island.
Solar Farm | SEBANE
In an updated timeline, the states want electric distribution utilities to enter contracts with the bidders by Jan. 15, which would be filed with the states’ regulators by March 1.
The states ended up focusing on renewable generation projects and bypassed transmission. Two high-profile projects that would have imported Canadian hydropower did not make the cut: Eversource Energy’s Northern Pass, which is planned to run through New Hampshire; and Anbaric Transmission’s Vermont Green Line, which would have connected wind power in New York, combined with Canadian hydropower, and be buried under Lake Champlain and underground in Vermont.
Several transmission projects that would move wind power from Maine to load centers farther south were also rejected in the RFP. Eversource’s 600-MW Clean Energy Connect between Massachusetts and New York did not advance.
“We are pleased with the key approvals the project continues to receive and look forward to participating in the April solicitation for large-scale hydroelectricity,” Bill Quinlan, president of Eversource New Hampshire Operations, said in a statement. “The region’s energy landscape is shifting quickly. Northern Pass, with its 1,090 MW of clean hydropower, and permitting well underway on both sides of the border, is in a strong position to play an important role in helping the region achieve a cleaner energy future.”
LITTLE ROCK, Ark. — SPP celebrated its 75th anniversary this week with a gala featuring political and regulatory figures, an orchestral piece, a commemorative video and a coffee-table book.
The gala, held Monday night in downtown Little Rock, attracted more than 300 attendees, including Arkansas Gov. Asa Hutchinson and other state officials, FERC Commissioner Colette Honorable — former chair of the state Public Service Commission — board members, stakeholders and community leaders.
Left to right: Asa Hutchinson, Susan and Nick Brown, Colette Honorable | SPP
They were treated to the Arkansas Symphony Orchestra Brass Quintet’s rendition of “Heralding Light,” which was composed for the occasion.
SPP also marked the occasion by releasing a 20-minute video and a history book, both called “The Power of Relationships.” The book spent a year in development, with former SPP executive Les Dillahunty providing much of the preliminary work, and features comments from previous and current members and officers.
“SPP has long distinguished itself through our relationship-based approach to doing business,” SPP CEO Nick Brown and Board Chair Jim Eckelberger wrote in the book’s foreword. “SPP exists because of its shareholders. Period. Without their support — logistically, financially, politically and often even emotionally — we would not be where we are today, if we were anywhere at all.”
SPP was created by 11 regional power companies just nine days after the Japanese attack on Pearl Harbor in 1941 to ensure reliable energy for an aluminum plant supporting the wartime effort. The RTO now serves 18 million people across 14 states.
Ten things you may not have known about SPP (from “The Power of Relationships”):
SPP’s first computer had two memory cards “the size of a pizza box,” each with less than a megabyte of memory. “My iPhone now has more power in it,” says Malinda See, vice president of corporate services. One of SPP’s 14 original employees, See said she would take the reel-to-reel backup tapes home for safekeeping.
SPP’s operating budget, less than $53,000 in 1969, didn’t exceed $1 million until 1990. It’s currently $210 million.
Back when the fledgling organization had 14 employees, it nonetheless kept a strict accounting of the few fixed assets it had. “If they had to buy a chair,” CFO Tom Dunn recalls, “they had utility members ask, ‘Why do you need more chairs? What happened to the old chair?’”
Dillahunty | SPP
SPP’s original 11 members were future Entergy operating companies Arkansas Power and Light, Louisiana Power and Light and Mississippi Power and Light; future American Electric Power subsidiaries Public Service Company of Oklahoma (PSO) and Southwestern Gas and Electric (now Southwestern Electric Power Co.); Southwestern Light and Power (later acquired by PSO); Empire District Electric; Kansas Gas and Electric (now Westar Energy); Nebraska Power (Nebraska Public Power District); Oklahoma Gas & Electric; and Texas Power and Light (Luminant, Oncor and TXU Energy).
Dillahunty and Jay Caspary, now director of research, development and Tariff studies, were recognized by the Kansas House of Representatives as honorary citizens in 2006 for the amount of time they had spent in the Sunflower State working on transmission-expansion development.
Board Chair Jim Eckelberger, a retired U.S. Navy rear admiral, and Director Harry Skilton have been with SPP since before it gained RTO status in 2003. They were both part of an independent board seated in 2000 as a precursor to RTO status.
It took three attempts and three years before SPP was approved by FERC as an RTO. In the interim, SPP also tried to merge twice with MISO, calling the effort off for good in March 2003.
Former CEO John Marschewski once accidentally locked himself out of SPP’s offices in the days before identification badges. Marschewski waited for another tenant to let him in the building, then removed drop ceiling tiles and climbed over the wall to get into his office from the hallway.
CFO Tom Dunn dressed as Superman for a company-wide function several years ago. Unfortunately, his superpowers failed him when he tried to fly off the stage. He broke one foot and bruised the other upon landing.
The largest outage in SPP’s history came in July 1993 when sagging power lines tripped after coming into contact with trees and resulted in the loss or reduction of more than 300 MW of load. The interruption was centered on the four-state border area of Arkansas, Kansas, Missouri and Oklahoma.
Meeting California’s 50% by 2030 renewable standard could require up to $5 billion or more in transmission upgrades, according to a report released this week by the California Energy Commission.
The report outlines what transmission projects the state must build or upgrade to connect load zones with areas identified as having the potential to provide more than 40,000 MW of new renewable capacity.
The study is a product of the Transmission Technical Input Group (TTIG) convened under the Renewable Energy Transmission Initiative (RETI), a collaboration that includes CAISO, the state’s major municipal and investor-owned utilities, the Western Area Power Administration and the California Natural Resources Agency.
RETI has determined that California will need an additional 25 to 108 TWh of renewables annually to meet its mandate, depending on growth in vehicle electrification, adoption of behind-the-meter solar and the success of energy efficiency programs.
That translates into 7,000 to 31,000 MW of new capacity, assuming a 40% average capacity factor, or 9,000 to 41,000 MW assuming a 30% capacity factor.
It also estimates building all of the transmission identified would cost more than $5 billion.
The TTIG said the capital costs included in the report are considered “conceptual” or “high-level” estimates that were derived from previous studies, which “should not be considered as reliable for specific resource addition purposes.” Actual costs — including those for meeting the lower-end estimate of new renewables — will depend on a combination of factors, including the cost-effectiveness of developing a specific set of resources and the transmission paths necessary to reach them.
While California has a “substantial amount” of non-firm capacity to interconnect new generators as energy-only resources subject to curtailment, the state falls short in the availability of full-capacity interconnections equipped to ensure that output is “fully deliverable” — or capable of reaching its load sink without hitting potential constraints.
California rules allow the state’s utilities to count only fully deliverable generation toward their resource adequacy requirements, excluding energy-only resources. For that reason, the TTIG, headed by CAISO Director of Infrastructure Development Neil Millar, assumed that all new renewable resources would require full-capacity interconnections.
CAISO can accommodate an additional 22,000 MW of energy-only resources, the report notes. The ISO is so far the only balancing authority area in the state to have studied the issue, so other BAAs have the potential to contribute additional energy-only capacity.
To perform its analysis, the TTIG broke the state into eight transmission assessment focus areas (TAFAs) where the large quantities of renewables could be developed to meet the state’s 2030 goals.
The Renewable Energy Transmission Initiative report examined the potential for developing renewables in eight California regions — as well as the transmission cost for reaching the resources. | California Energy Commission
“The TAFAs identify a ‘hypothetical’ development potential for wind, solar and, where applicable, geothermal resources,” the report says.
Those hypotheticals show a combined 15,000 MW of potential renewable development — mostly solar — in Southern California’s Imperial Valley, Riverside and Victorville/Barstow areas. To tap some of that potential, load-serving entities could have to foot up to $1 billion to relieve a constraint east of the Miguel substation close to the border with Mexico. A $34 million upgrade to the relatively short 500-kV Lugo-Victorville line could provide 2,000 MW in incremental capability, the report shows.
In the central part of the state, the San Joaquin Valley and Tehachapi TAFAs together have the potential for another 10,000 MW of mostly solar resources. While San Joaquin would require about $400 million in transmission upgrades, Tehachapi would require a negligible amount of work.
The least promising area: all points north of San Francisco and Sacramento, where it would cost $2 billion to $4 billion to tap an estimated 5,450 MW of wind, solar and geothermal resources — the largest share of the $5 billion estimate.
“The bulk transmission system in the region is heavily utilized and would require substantial investment to allow for the delivery of new full capacity resources,” the report says.
The study also evaluated the potential for sourcing additional renewable energy via California’s major interties, including the California-Oregon Intertie in the north (2,000 MW), the Palo Verde-Delaney line to Arizona (3,000 MW) and the Eldorado/Mead/Marketplace (3,000 MW) links with Nevada. All three were found to be subject to the same constraints as the TAFAs with which they interconnect, compounded by the fact that the imported energy would compete with TAFA resources for transmission access.
Entergy reported third-quarter earnings of $2.16/share Tuesday, beating analyst expectations, but its stock continued a months-long decline.
Despite beating Wall Street predictions of $1.95/share, according to Zacks Investment Research, Entergy shares have lost about $2.48/share since Monday’s close, a 3.3% drop. Its fall below $72/share continued its slide since setting a 52-week high of $82.08 in early July.
Nine of 11 analysts tracked by Zacks rate Entergy stock as a hold, with one rating it a strong buy and another a strong sell.
After the earnings report, Morgan Stanley downgraded Entergy to underweight, citing weak sales and risks to earnings from the potential disallowance of nuclear costs. It set a $68 price target.
Logo on Entergy Building in New Orleans, La. | photonews247.com
Entergy has announced it plans to shutter its Vermont Yankee (already being decommissioned) and Pilgrim (in 2019) nuclear plants in New England, and the company is attempting to sell its James A. FitzPatrick unit in New York in Exelon. Costs related to the closures were reflected in the corporation’s 2015 earnings, Entergy CEO Leo Denault said during a conference call with industry analysts Tuesday.
Denault said the company’s Arkansas and New Orleans operating companies have made filings with state regulators seeking approval to deploy advanced metering infrastructure (AMI) as early as 2019. Denault said AMI “will lay the foundation for an integrated energy network.”
Theo Bunting, Entergy’s group president of utility operations, told analysts the corporation has projected its total AMI investment at $900 million “on a system basis,” and includes development of the technology’s backbone.
“As you go through the filings, you will see that there were some costs we’re asking to defer that will get fully incurred prior to the full functionality of the meters themselves,” Bunting said. “We also believe that infrastructure is useful for other systems as well. So I think our perspective is the cost is consistent with what we’ve seen in implementations across the country.”
“We continue to make those modernizing investments that will lower production cost [and] provide significant benefits to our customers,” said Denault, adding that the corporation’s financial outlook reflects “our prudent decision to position the nuclear fleet for sustained operational excellence.”
Denault also told analysts the company has 48 projects “totaling roughly” $480 million up for consideration in MISO’s 2016 Transmission Expansion Plan (MTEP). Entergy has submitted another $700 million of proposed projects for MTEP 2017.
“We will work with MISO on the selection process for those proposals over the course of the next year,” Denault said.
The company says it expects earnings of $6.60 to 7.40/share for the year.
FERC granted a Maryland solar developer’s request to reinstate its position in PJM’s interconnection queue, which the company lost because of delays in obtaining state approval (ER16-2645).
Dan’s Mountain Solar initiated the interconnection review process in 2014 to connect its 18.36-MW project in Allegany County to Potomac Edison’s 138-kV Frostburg-Ridgeley line.
The developer obtained its facilities study from PJM in December 2015, triggering a 60-day countdown for signing the interconnection service agreement (ISA). PJM later extended the ISA deadline to June 2, 2016.
But the developer didn’t receive its Certificate of Public Convenience and Necessity from the Maryland Public Service Commission — a requirement for signing the ISA — until July 11, two-and-a-half months after the state had promised a decision and just more than a month after the project was automatically withdrawn from the PJM queue on June 7.
Because transmission upgrade costs are determined by a unit’s interconnection position, PJM intervened to note that reinstating Dan’s Mountain’s queue position could disadvantage interconnection applications that have been filed in the interim. But in a Sept. 21 email to the developer, PJM acknowledged that as of that date, no other projects would be negatively impacted by its reinstatement.
FERC granted the developer’s request for a waiver of the deadline following an expedited review, saying “it appears this waiver will not harm third parties.”
“Although PJM’s Oct. 6, 2016, comments assert that the potential for harm to third parties increases as time passes, PJM did not indicate that harm is imminent,” the commission said in its Oct. 25 order.
The waiver allows Dan’s Mountain to continue where it left off and avoid restarting the application process.
The Sacramento Municipal Utilities District (SMUD) will join the Western Energy Imbalance Market (EIM) in spring 2019 at the earliest, according to the head of the joint powers agency of which the utility is the largest member.
Shetler | United Way
“As you might guess, this is a very intense technical project,” Jim Shetler, general manager of the Balancing Authority of Northern California (BANC), told RTO Insider.
The four utilities that have joined the EIM to date have required 18 to 24 months to begin operating in the EIM after signing an implementation agreement with CAISO, the market’s operator.
SMUD will likely sign such an agreement early next year, Shetler said. “We’re just starting to meet with the ISO to lay out project plans.”
The utility announced its intention to join the EIM on Oct. 21, citing the benefits of increased renewable integration, potentially reduced reliance on gas-fired generation and lower operational costs. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)
SMUD would be a first municipal utility to sign up for the market — a status that could potentially complicate its efforts to join. Municipal utilities are not subject to FERC jurisdiction — but the EIM is. (See Co-ops, MISO, SPP Urge FERC Restraint with Nonpublic Utilities.)
“With FERC oversight, we’re trying to understand what that would mean,” Shetler said. “SMUD has an open access transmission tariff that was approved by its board, but not by FERC.”
SMUD already operates under an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas.
A joint study conducted by BANC and the Western Area Power Administration estimated that SMUD would gain $2.8 million in yearly net benefits from transacting in the market — a figure that nets out an estimated $6.7 million in implementation fees and $2.6 million in annual operations costs.
Shetler said that SMUD’s annual benefit could increase to about $5 million after five years, once the utility has paid down startup costs.
“It’s a big number, but a small number compared with their energy resource portfolio,” Shetler said. The real value will come in integrating the increased number of variable resources needed to meet California’s 50% by 2030 renewable energy mandate, he noted.
Sacramento Municipal Utility District headquarters | SMUD
SMUD would be breaking ground for possible future EIM participation by BANC’s other municipal utility members, including Modesto Irrigation District and the cities of Redding and Roseville.
Two other members — the city of Shasta Lake and Trinity Public Utilities District — own no generating resources and would therefore derive no benefit from joining the market, Shetler said. Trinity, a “full requirements” customer of WAPA, receives all of its energy from the federal agency.
Could other BANC members piggy-back on SMUD’s efforts and reduce their costs to join the EIM?
“We’re hoping that’s the case,” Shetler said. “We think there is some scale there.
“Not that it would be on the backs of SMUD or its ratepayers,” he added.
Established in 2011, BANC is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. The agency is responsible for balancing load among its members, as well as coordinating system operations with neighboring balancing areas.
BANC contracts with SMUD to perform day-to-day balancing functions.
The BANC-WAPA study spelling out EIM benefits is slated to be released to the public in late November.
COLUMBUS, Ohio — More than 150 regulators, PJM officials and stakeholders gathered for last week’s annual meeting of the Organization of PJM States Inc. Here’s some of what we heard.
American Public Power Association CEO Sue Kelly, who appeared on a panel on PJM’s Capacity Performance model with Independent Market Monitor Joe Bowring and RTO officials, Calpine and two utilities, noted that it was her fourth such appearance before OPSI. As the lone critic of mandatory capacity markets, she joked, she felt like “the token Republican on MSNBC.”
She said the changes going on “at the end of the grid,” such as solar and demand response, are going to make CP “outmoded.” It “does not meet public-policy goals. It wasn’t designed to meet public-policy goals,” she said.
PJM General Counsel Vince Duane said there are “a whole host” of “entirely valid” public-policy goals that PJM must balance in its designs. “So it’s not a question of which policies are more important,” he said. “There’s a lot of evidence out there that we’ve done the design job very well.”
The focus needs to be on developing the flexibility for states to make policy goals while ensuring the viability of CP, he said.
He said it’s a “gross over-reading” of the Supreme Court’s Hughes v. Talen ruling to believe that any state subsidy would interfere with wholesale markets. (See Supreme Court Rejects MD Subsidy for CPV Plant.) “We can’t let the markets be used to obscure and disenfranchise the political process,” he said.
Bowring repeated his concerns that competitive markets are threatened by state-subsidized generation, as proposed in Ohio. “There is a line, and the line has to do with price formation and the integrity of the market,” he said. “To the extent that the line isn’t drawn, then the markets won’t survive.”
Kelly said the Hughes case gives states and public power utilities “a lot of options” for implementing public policies without violating federal jurisdiction. “I don’t think we should just count on that court case to squash all of this. I think it would be much better if we collectively work this out than go back to the Supreme Court three more times,” she said.
Lathrop Craig of Public Service Enterprise Group asked if a market dominated by gas, supported by renewables and experiencing major declines in coal “still makes a lot of sense” and whether a unit’s value to the market should rely on something other than its lack of emissions.
Bowring wasn’t in favor of what he described as subsidizing old units “because you don’t like where the market’s going.”
“I don’t think that’s a good idea,” he said.
Kelly raised concerns about relying too heavily on gas. “It’s kind of like dating your first husband — you have bad memories,” she said. “I have memories of gas at $3.50. I have memories of gas at $14.50. I have memories of having my contract ripped up by FERC and having to go out and replace all that.
“Things are great till they’re not great,” she added, citing concerns that fracking is causing earthquakes in Oklahoma and a rise in demand for LNG could boost gas prices.
In another panel, stakeholders discussed how state renewable portfolio standards are the largest driver of the surge in renewables on the grid. PJM’s Chantal Hendrzak outlined several initiatives the RTO is undertaking, including developing wind and solar forecasts and researching better integration of renewables and battery storage, to ensure that “when renewables come on the system, no matter how they come on the system, that we can reliably integrate them.”
The industry has moved quickly to implement states’ renewable portfolio standards, said Exelon’s Bill Berg. “Some of the lofty goals passed a few years ago now seems within reach,” he said.
As usual, the conference ended with OPSI’s Market Monitoring Advisory Committee’s meeting — an annual check-up on the status of relations between the Monitor and PJM.
Bowring said his “overall” relationship with PJM “is good,” but he noted one exception. He said the “very public” disagreement over how the Monitor interacts with PJM has resulted in “pretty tough filings back and forth on the hourly flexibility proceeding.” (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
Virginia State Corporation Commissioner Mark Christie commended Bowring, while noting that “not everyone agrees with” him.
“It is really all about making sure the markets are as efficient as possible, and we’ve always viewed the Independent Market Monitor as critical to that,” Christie said. “We certainly respect his honesty, his talent, his willingness to tell it like it is, like he sees it. Those who disagree can disagree.”
PJM Board Chairman Howard Schneider interjected, “We agree with that 100%.”
Earlier, Schneider had announced board member Susan Riley as the new chair of the Competitive Markets and Governance Committee, which oversees the engagement between PJM and the Monitor. Riley assured the audience that the committee has regular contact with Bowring, and he has unfettered access to bring issues to the board.
“Each issue that he raises is, in fact, researched with PJM, with Joe, with Joe’s staff, and we try to arrive at resolutions we can — more times than not — agree on,” she said. “The working relationship has evolved and grown over the past nine years, and I would say from where I sit that it’s working very well right now.”
Bowring agreed.
American Municipal Power’s Ed Tatum, who asked the only question during the brief meeting, appreciated the collegial tone. “The troubles are over. The waters are more still, and that’s good,” he said.
FERC on Thursday rejected CAISO’s effort to refund $220 million to scheduling coordinators that the ISO said were misallocated payments to generators operating under must-offer obligations.
The decision rendered moot a complaint filed by energy retailers that contended that the refunds were unjustified because they had not been specifically ordered by the commission (EL14-67, et al.).
While the ISO’s refund report did not specify the beneficiaries of the refunds, other documents related to the proceeding indicate that a portion of the payments were likely destined for Southern California Edison customers in light of a previous FERC decision to reallocate must-offer costs associated with a transmission constraint within the utility’s service territory to all load in CAISO’s SP-15 zone.
At issue was a May 2004 Tariff amendment that changed the allocation of minimum load costs — fuel costs associated with keeping a unit running at minimum levels — for must-offer generation to more accurately reflect cost causation.
CAISO sought to issue refunds – in part – because of FERC’s decision to reclassify the benefits of must-offer generation located south of the Lugo substation located within Southern California Edison’s service territory. | California Energy Commission
Under the design, CAISO allocated minimum load compensation costs to load-serving entities based on whether the generators had primarily fulfilled local, zonal or system reliability requirements.
FERC approved most of the amendment two months later, but the cost allocation provision — which had been contested by Pacific Gas and Electric — was subject to modification and rehearing, with a refund date set for July 17, 2004.
In December 2006, the commission mostly affirmed the reasonableness of the allocation provision, but it found that the South of Lugo Transformer Path in Southern California should be classified as a local — rather than regional — constraint. FERC ordered the ISO to allocate must-offer start-up and emission costs in the same manner as minimum load costs and determined that wheel-through transactions should be excluded from the allocation.
Southern California Edison protested the reclassification of the South of Lugo constraint as local, an argument with which the commission later agreed in a 2007 rehearing. The cities of Anaheim, Azusa, Banning, Colton and Riverside, in turn, contested that decision, but the D.C. Circuit Court of Appeals denied their petition for review in 2013.
Later that year, CAISO submitted to FERC a report outlining refunds the ISO intended to issue based on the reallocation of must-offer costs stemming from the prior rulings. Issuing the refunds would require the ISO to levy surcharges on scheduling coordinators that paid too little in order to make whole those that paid too much.
Shell Energy North America and the Alliance for Retail Energy Markets — representing Constellation NewEnergy, Direct Energy and Noble Americas Energy Solutions — contested the surcharges, saying that they were effectively retroactive rate increases not authorized by FERC. They also argued that, when the commission requires refunds, “its normal practice is to expressly order that refunds be made within a specified time and that a refund report be filed,” neither of which occurred. In any case, FERC was not obligated to require refunds in this case, they said.
Those contentions found support in the commission’s decision last week.
“CAISO’s filing of the refund report is not tied to any commission compliance directive in this proceeding,” the commission wrote. “While the commission initially accepted CAISO’s filing subject to refund, at no point did the commission direct CAISO to make refunds or file a refund report.”
The commission also found that the ISO at no time overcharged its customers and that it had appropriately revised its Tariff on compliance so that a just rate was allocated to customers on a going-forward basis.
Furthermore, the commissioners pointed out that none of its prior orders stated that the ISO had failed to follow any directives by not issuing refunds.
Transmission Line Leading to Lugo Substation | Edison International
“Even if it were arguably unclear whether refunds should have been ordered for past periods, we note that neither CAISO nor any other party sought rehearing or clarification of the orders in this proceeding on this issue,” the commission said.
FERC went on to state that “surcharging of market participants was improper for any past periods” and that its power to order refunds is “discretionary” under the Federal Power Act.
The commission said the complaint by the alliance and Shell “has been rendered moot as a result of our rejection of the refund report.”
Electric cooperatives accused FERC on Friday of overstepping its authority by opening proceedings that could force refund obligations on nonpublic utilities, while MISO and SPP asked the commission to let them work out the issue in stakeholder proceedings.
At issue are FERC’s July orders opening Section 206 proceedings in MISO and SPP (EL16-91 and EL16-99). FERC said that it may be unjust and unreasonable for the RTOs to exempt nonpublic transmission owners from the refund requirements it mandates for public utilities. (See FERC: MISO, SPP Need Refund Requirements for Nonpublic Utilities.)
NRECA’s Argument
Tracy Warren, senior communications officer at the National Rural Electric Cooperative Association (NRECA), said the proceedings amount to a “work around” for FERC to regulate electric cooperatives and nonpublic utilities that are not under commission ratemaking authority. “We believe FERC is trying to extend its jurisdiction,” she said.
Rural Electric Cooperative line workers in Oklahoma | Rural Electric Cooperative
In its initial brief in the 206 proceedings, NRECA said a refund requirement could deter nonpublic utilities from joining RTOs. NRECA also acknowledged in its filing what it called FERC’s “legitimate concern” in ensuring that MISO and SPP abide by the Federal Power Act.
“However … NRECA cautions the commission against threatening the progress made in transmission-owning [nonpublic utilities] becoming members of MISO and SPP. … Maintaining their non-jurisdictional status is critical for [nonpublic] cooperative utilities deciding whether to join an RTO,” NRECA wrote.
Although FERC acknowledged in the proceedings that it cannot directly order refunds from nonpublic utility transmission owners that have joined RTOs, it suggested SPP and MISO could indirectly enforce refunds. NRECA, which represents more than 900 nonprofit rural electric utilities, said the measure would force co-ops and municipal utilities to “volunteer” to pay revenue refunds if they want to recover transmission revenue requirements.
“Long-standing interpretations of the Federal Power Act confirm that the majority of our members lie outside FERC’s ratemaking and refund authority; yet with these proceedings, FERC is working to undermine those interpretations,” NRECA CEO Jim Matheson said in a statement. “By pushing to alter the limits of its jurisdiction over rates for services provided under the tariffs of MISO and SPP, FERC actions could have a chilling effect on efforts to encourage market participation by nonpublic utility transmission owners. FERC has long acknowledged co-op and municipal participation as critical to the success of RTOs.”
Matheson said RTOs should work with stakeholders to develop solutions on how to make refunds more equitable. If FERC insists on requiring refund provisions for nonpublic utilities, NRECA said, it should limit the commitments to transmission service costs and leave out revenues from “participation in other markets or services.”
Other nonpublic utilities — Hoosier Energy Rural Electric Cooperative, Sunflower Electric Power, Mid-Kansas Electric, Nebraska Public Power District and Midwest Energy — also filed initial briefs cautioning FERC against mandating refunds.
SPP and MISO: Let Stakeholder Processes Work
In their briefs, MISO and SPP asked FERC to let them seek a consensus solution in their stakeholder processes.
SPP said FERC should avoid “mandating prescriptive revisions,” saying the RTO’s staff and stakeholders are in the best position to address the “complex legal and operational issues” involved.
The RTO admitted that it has struggled with the refund discrepancy. “The disparity in refund obligations between public utility and nonpublic utility transmission owners has presented legal and administrative difficulties for SPP and other RTOs in the past. SPP welcomes the commission’s focus on this issue,” SPP wrote.
MISO similarly asked that its staff and public and nonpublic transmission owners be allowed to revise refund rules on a “consensual basis through an open process.”
The RTO said it could run into legal difficulties if FERC orders a specific Tariff revision, because it is legally bound to not only its Tariff, but also its Transmission Owners Agreement.
“To the extent the commission decides to impose any refund commitment requirements, merely directing MISO to revise its Tariff, without considering corresponding revisions to the Transmission Owners Agreement, could expose MISO to legal challenges or require it to take positions on matters that potentially could fall within the purview of its owners,” MISO said.
The RTO also said any steps FERC takes should protect MISO’s status as a revenue-neutral entity.
COLUMBUS, Ohio — PJM’s Craig Glazer opened a panel on controlling transmission project costs at last week’s annual meeting of the Organization of PJM States Inc. with a tongue-in-cheek game show: “Who Does What?”
The series of multiple-choice questions he presented highlighted the lack of clear authority throughout the transmission-development process, with state regulators, RTOs and FERC all potentially playing a role.
Who decides which of three cost-capped transmission proposals — differing on what costs are covered and what are excluded — is the best for ratepayers? Who enforces the cost cap after an award?
“There are no clear answers,” said Glazer, PJM’s vice president of federal government policy. “This is about one of the fuzziest areas we’ve got.”
That set the stage for a dialogue on transmission planning that spanned two panels and more than three hours of discussion. The first panel tiptoed around the troubled Artificial Island project to debate the advantages and challenges of cost caps. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
The second panel focused on FERC’s recent decision to investigate how supplemental projects are awarded. It pitted incumbent transmission owners against independent transmission developers and the customers who pay to use their networks in debating how receptive TOs should be to outside opinions on how to manage their assets. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
Sharon Segner of LS Power, who sat on both panels, outlined her argument in detail. She started by campaigning for FERC to issue a policy statement defining the elements of cost caps, contrasting it with nonbinding cost estimates.
Segner said cost-containment proposals must be specific about what costs are covered and what are excluded, including legal caveats. And those promises must be incorporated into the designated entity agreement and rate case to ensure enforceability, she said.
“A PowerPoint proposal, in our view, is not a cost-containment proposal. It has to be clear, and the legal language has to be clear as well,” she said. “The selection process should fairly and truly weight the cost-containment proposal.”
Jodi Moskowitz of Public Service Enterprise Group said cost caps make sense in theory but can be challenging in implementation. First, she said, the 45 days PJM has given bidders to respond to solicitations is not enough time to develop accurate cost estimates.
She also raised the issue of permitting delays, citing the Susquehanna-Roseland reliability project that PSEG built with PPL. It took four years to win National Park Service approval for a crossing through the Delaware Water Gap National Recreation Area even though it was completely within an existing right of way, she said.
“The challenges associated with these large, linear projects is intense,” she said, noting that “the cheapest project may not provide the overall best value to customers.”
She pointed out that FERC, in its acceptance of PJM’s Order 1000 compliance filing, rejected a cost-cap proposal, noting that many of the issues involved with project development are out of the developer’s control.
“Competitive transmission — we struggle with that term,” she added, questioning whether competitive developers’ designs are equal to her company’s standards. “We only have one grid.”
Josh Burkholder of Transource Energy, a joint venture of American Electric Power and Great Plains Energy, said proposals that offer both guaranteed cost caps and significant cost savings are “too good to be true.”
“This has me scratching my head, because if risks are truly transferring [from customers to the developer], you would expect there to be an associated risk premium.”
In response to that pressure, his company attempted to share the cost risks with its construction vendors, equipment manufacturers and companies acquiring rights of way.
“That process has been very, very challenging,” he said. “There are risks that our suppliers are just flat-out not interested in taking. They have plenty of work that they can do without assuming a lot of new risks.”
Including its risk premium in its Artificial Island bid made it uncompetitive, he said.
Attorney Robert Weishaar, who represents the PJM Industrial Customer Coalition, said Order 1000 “has yet to deliver tangible benefits.”
“We think FERC needs to redouble its efforts to provide clear directions to RTOs on how … to fully implement Order 1000 and deliver on its promises,” he said.
Weishaar also said FERC should eliminate rate incentives — such as those for RTO participation and independent transmission companies — in Order 1000 projects. “This is competition,” he said. “There are no regulatory incentives in competition.”
In the second panel, Exelon’s Gloria Godson and Bob Bradish of AEP passionately defended transmission owners’ authority to manage their assets without second-guessing.
“I have a good relationship with some of my neighbors. Some of them, I really don’t like the way that their doors look. I think that they should change their doors, but I have never gone over to my neighbor and said, ‘You know what? I’m going to take down your door and change it,’” Godson said. “You just don’t do that to someone else’s assets. It’s just not courteous. It’s not nice!”
“We have a set of standards,” Bradish added. “We’re certainly happy to sit and debate standards, but we don’t want someone’s opinion to substitute for 110 years of doing the work.”
He called suggestions from stakeholders on what specific components to use “not helpful.”
American Municipal Power’s Ed Tatum said the fact that his company is helping to foot the bill is what qualifies him to be part of the decision.
And he said that bill has jumped sharply in recent years. In the earlier panel, he had pointed to a transmission expansion in Jersey Central Power and Light’s territory whose costs ballooned from $22 million to $111 million once estimates had been more “fully refined,” according to the presentation at the Oct. 6 Transmission Expansion Advisory Committee meeting.
“We’re not asking to paint anybody’s door … but what we are concerned about is what’s being built and why. The reason is because we’re paying for it. If we’re paying for it … we should talk about it.”
Segner said her company is concerned the supplemental project process allows incumbent transmission owners to win projects that should be open to competition.
She also voiced concern that the Transmission Replacement Processes Senior Task Force — which has been assigned to develop rules and review processes for “end-of-life” projects — has a flawed mission and no means to repair it.
“The solution is not more PJM slides. It’s not prettier slides,” she said. “There needs to be fundamental reform in the local planning process, and that’s where the transparency needs to be.”
Earlier in the panel, PJM Vice President of Planning Steve Herling explained the RTO’s plans to restructure the TEAC to be more dynamic and communicative.
“We’re going to be putting more and more of the material out, essentially in kind of webcasts well in advance of the TEAC meeting,” he said. “Our goal is to have this material all available before we get to the TEAC or the sub-regional [Regional Transmission Expansion Plan] committees so that you can educate yourself about a particular problem, about a solution option that is out there and then engage in Q&A with PJM or with the transmission owners.”
PJM’s hopes to implement the changes by the beginning of the 2018 RTEP cycle, but enhancements will be rolled out as they are ready.
