SACRAMENTO, Calif. — Gov. Jerry Brown on Wednesday reaffirmed his commitment to an expanded CAISO, a month after asking state agencies to delay their efforts to complete enabling legislation.
Brown told the ISO’s annual stakeholder symposium that greater cooperation with balancing authority areas in neighboring states is essential to increasing the efficiency of the grid and meeting California’s ambitious renewable portfolio standard of 50% by 2030. The governor signed a bill Thursday to reduce the state’s greenhouse gas emissions to 40% below 1990 levels by 2030. (See California Legislature Approves Bill to Sharply Reduce GHG Emissions.)
“I think we recognize the imperative of making our electric system as efficient as it possibly can be,” Brown said. “The efficiency of a wider grid is unmistakable. And the imperative is greater efficiency, greater elegance and intelligence in the way we use and produce electricity, the way we market it and the way it goes around the system.”
Brown listed some of the dangers to California from climate change — including longer wildfire seasons and the potential for flooding in low-lying areas — and asked how California can work with other states “that have different perspectives” on dealing with climate change.
“That’s something I think you’re all here to figure out, because we’re not going to change differences in different states that have different needs and different experiences,” Brown said.
The governor noted that utilities in his own state at one time doubted the possibility that they could sustain a 20% RPS by 2020. But those companies are now on track to exceed that goal and are confident they will hit the 50% objective.
“But in order to get there, we need a grid that is highly sophisticated,” he said. “We need a grid that is conterminous with the technology and capability that is possible today.”
“So I hope you work all that out,” Brown added, humorously. “Make sure that those who love coal and those who love the sun can sit down and work in a totally seamless web of interconnection, interaction and happiness for all.”
Brown acknowledged the difficulty of advancing regionalization through the political process of multiple states. The governor last month postponed plans to present the legislature with a governance plan for an expanded ISO, saying there wasn’t enough time to complete the proposal before the legislative session ended Sept. 1. (See Governor Delays CAISO Regionalization Effort.)
“But the times are changing, and the technologies are forcing us to reexamine how things work,” Brown said.
Five New York City-area legislators, including the chair of the State Assembly Committee on Energy, wrote to state regulators last week questioning the ratepayer-funded nuclear power plant subsidy and requesting disclosure of the operating costs of the affected plants.
The New York Public Service Commission last month approved a Clean Energy Standard that includes a subsidy for upstate nuclear power plants. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.) In May, the commission granted Exelon’s request to keep the operating costs of its R.E. Ginna and Nine Mile Point 1 and 2 plants private (16-E-0270).
“Why should Exelon’s costs be blocked from public review when it is being given a government-directed and government-administered price subsidy?” the legislators wrote.
The zero-emission credits created by the order are expected to cost ratepayers $965 million in the first two years of their 12-year existence. Included in the subsidy is Entergy’s James A. FitzPatrick plant, which Exelon has agreed to buy. (See FitzPatrick Sale Filed with New York Regulators.)
The assemblymembers also said that Nine Mile Point 2 should be eliminated from ZEC payments and the cost of the program should be recalculated. They said the fact that Exelon refueled the plant in the spring indicates that that the facility is not financially stressed or in danger of closing.
“In the commission record, we take note that Entergy announced intentions to close FitzPatrick, and Exelon announced intentions to close R.E. Ginna and Nine Mile 1, but no formal announcement was made regarding intention to close Nine Mile 2, which produces 40% of the electricity of the four units. Without a publicly transparent cost review, and in light of the recent refueling of the unit, the payment should be removed from the commission’s order,” the letter said.
Nine Mile Point
The letter also states that downstate ratepayers will be paying a disproportionate share of the subsidy — 60% — while most of the energy generated by the plants will be used upstate, closer to the plants’ locations in western New York.
The assemblymembers also said that the subsidy is based on EPA’s projected social cost of carbon, which could increase as much as 10% every two years after the first two years of the program.
The letter was signed by Energy Committee Chair Amy Paulin, who represents Westchester County; James Brennan of Brooklyn; Jeffrey Dinowitz of the Bronx; and Steve Englebright and Charles Lavine of Long Island.
In a response on Friday, PSC Chair Audrey Zibelman said there are “a number of fundamental errors” in the lawmakers’ understanding of how the power system works and the CES’ role in it.
Zibelman said the price of renewable energy credits is set by a competitive bidding process, but with few participants, ZEC prices must be set administratively. The federal social cost of carbon is a more effective mechanism and accounts for the externalities associated with fossil fuel generation, she said.
“Second, it is simply wrong for anyone to suggest that we can achieve targeted emission reductions by 2030 if we were to lose the zero-emissions attributes of the three upstate nuclear plants. Experience and fundamental economics show that the zero-emissions attributes they produce and New York needs will be replaced by adverse air emissions from existing coal and new natural gas-fired fossil units that can be dispersed throughout the state or come from out-of-state imports,” Zibelman wrote
The cost of replacing all of the nuclear generation with renewables would be more expensive than the ZECs, she added.
Finally, she disputed the assertion that the New York City area is being treated unfairly. “The CES allocates the obligation to meet the 50% renewables goals and zero-emission credits to all of the consumers of the state because all consumers will benefit from reducing carbon emissions,” Zibelman wrote.
WASHINGTON — A public interest group and Connecticut officials asked a federal appellate court Tuesday to force FERC to rule on the legality of ISO-NE’s eighth Forward Capacity Auction, saying the commission abdicated its responsibility by refusing to take action.
In September 2014, the commission split 2-2 over whether it should reject the results from the RTO’s auction because of unchecked market power, allowing the 2017-18 auction results to become “effective by operation of law” (ER14-1409). Under the Federal Power Act, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary.
Commissioners Tony Clark and Norman Bay called for FERC to reject the auction results, but then-Chair Cheryl LaFleur and Commissioner Philip Moeller said the commission should seek only prospective changes in the auction rules. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
Tuesday’s arguments before a three-judge panel of the D.C. Circuit Court of Appeals focused less on the auction itself than on whether the commission’s 2-2 deadlock constituted an “action” that should be subject to judicial review. FERC contends it was an exercise of the commission’s discretion and thus not subject to second-guessing (14-1244).
Remand Sought
Scott Nelson, attorney for plaintiff Public Citizen, said the court should remand the issue to FERC for consideration of whether the auction prices were just and reasonable, as he said is required by FPA Section 205 when a rate is challenged.
He cited a statement from LaFleur contending the commission lacked authority to review the auction results, an opinion FERC’s attorneys have not embraced. LaFleur said the ISO-NE Tariff is the “filed rate” and a review of the auction prices would violate commission precedent and subject auction participants to “regulatory uncertainty or after-the-fact ratemaking.”
“No one here actually defends that statement,” Nelson told the judges. “Here one of the determinative votes [on the auction results] rests on what is a clear error of law.”
The judges challenged Nelson’s arguments.
Brown Source: Judicial Council of California
Judge Janice Rogers Brown told Nelson his reliance on a precedent involving the Federal Election Commission is “somewhat flawed” because the FEC’s enabling act explicitly allows judicial review of deadlocks. “Where is that in the Federal Power Act?” she asked.
FERC Solicitor Robert H. Solomon also challenged the FEC precedent. With equal numbers of Democratic and Republican appointees, Solomon said, the FEC is “designed to deadlock.” In contrast, FERC is split 3-2, with the majority representing the party in the White House.
Judge Sri Srinivasan pressed Nelson on his use of another precedent, Amador County v. Salazar, noting that the FPA allows challenges under Section 206 if the commission fails to act under Section 205.
No ‘Backstop’
“That [Section 206] remedy is not an adequate alternative,” Nelson responded, noting that while ISO-NE must prove that its rates are just and reasonable under Section 205, the burden of proof flips to the plaintiffs in Section 206. In its brief, Public Citizen noted that the D.C. Circuit has previously ruled that Section 206’s burden of proof is “practically insurmountable” for private parties challenging rates.
“206 can’t be a backstop for the agency’s failure to exercise its authority under 205,” Nelson said.
John S. Wright, an assistant Connecticut attorney general, also argued for a remand. Connecticut’s challenge to the FCA 8 results (14-1246) was consolidated with the Public Citizen complaint.
“FERC has a duty to act,” Wright said. “FERC knew the rates were subject to the exercise of market power.”
The auction saw total capacity costs for 2017/18 rise to $3.05 billion — almost double the previous high — as the region’s capacity shifted from an expected surplus to a deficiency of more than 1,000 MW. The shortfall was because of plant retirements, including that of the 1,488-MW Brayton Point station in Massachusetts.
Brayton Point Source: Wikipedia
Wright said ISO-NE erred in the auction by treating capacity importers as “new” supply and not subjecting their bids to review, unlike existing resources. New resources in the Maine, Connecticut and Rest of Pool capacity zones were paid $15/kW-month, while existing resources in those zones received an administrative price of $7.025/kW-month.
However, FERC said its Office of Enforcement investigated Brayton Point’s retirement and determined it was justified.
In addition to announcing their deadlock in September 2014, the commissioners voted unanimously to open a new docket (EL14-99) calling for a Section 206 proceeding over the RTO’s process for reviewing importers’ offers and mitigating their market power. The commission approved Tariff changes addressing those concerns in December 2014 (ER15-117). (See FERC OKs Tightened ISO-NE Screening on Capacity Imports.)
‘Non-Order’
FERC’s Solomon said there is nothing for the court to review because the “commission made no decision.”
Statements issued by LaFleur and the other three commissioners were not official orders and thus not reviewable, he said. “What matters is whether anything has been articulated by the agency as an institutional body.”
The commission’s notice, he said, was a “non-order.”
Srinavasan Source: US Department of Justice
Srinivasan asked how often FERC has allowed rates to go into effect “by operation of law.”
“This is extremely rare, your honor,” Solomon responded, saying the commission has identified only six such instances in 80 years.
As evidence of the commission’s discretionary authority, Solomon quoted from subsections C, D and E of Section 205, which repeatedly use the word “may.”
Supporting FERC’s position Tuesday was Paul A. Mezzina, attorney for intervenor Electric Power Supply Association. Mezzina said that when market rules are followed, the results are “presumptively just and reasonable.”
Judge Brown pointed out that the settlement that led to the creation of ISO-NE’s capacity market says the commission “will” review the auction results.
But Mezzina said the settlement didn’t “take away any of the commission’s discretion to determine what the review consists of.” He said the commission has “broad discretion” and “no unequivocal obligation to act.”
FERC Chief of Staff Larry Gasteiger was among the FERC officials in the audience for the arguments. Also in attendance were representatives of some of the other intervenors supporting FERC: NRG Power Marketing, H.Q. Energy Services, Calpine, the New England Power Generators Association and the New England Power Pool Participants Committee.
Ruling
The FCA 8 rates will take effect June 1, 2017.
If the court rules that it has jurisdiction to review the commission’s inaction, it will have to decide whether the FPA allows a protested rate filing to go into effect when the commission cannot issue an order by majority vote.
Nelson said after the hearing he expected a ruling by March. Solomon said it could be as long as a year.
Were the issue to be remanded to FERC, Moeller, who left the commission last year, and Clark, who is stepping down this month, would have no role.
Following Clark’s departure, the commission will be short two members, with only LaFleur, Bay and Colette Honorable, who joined in January 2015.
Meanwhile, the capacity dispute has attracted the attention of the New England congressional delegation, which won House approval in March of a bill that would amend the FPA to allow court review of any inaction by the commission that allows a rate change to go into effect (HR 2984).
Canadian pipeline giant Enbridge is buying American pipeline company Spectra Energy in a $28 billion deal that will create North America’s largest energy infrastructure company.
Enbridge, which specializes in pipelines moving crude oil, will be moving into the natural gas transportation business with the all-stock transaction. Enbridge said in its news release that the acquisition will allow it to diversify both regionally and operationally.
The deal will give Enbridge a continent-wide system of natural gas, gas-liquid and crude oil pipelines, as well as terminals, gas distribution operations and a stable of wind, solar and geothermal generation.
Source: Enbridge
“Over the last two years, we’ve been focused on identifying opportunities that would extend and diversify our asset base and sources of growth beyond 2019,” Enbridge CEO Al Monaco said. “We are accomplishing that goal by combining with the premier natural gas infrastructure company to create a true North American and global energy infrastructure leader.”
11.5% Premium
Monaco will remain at the helm of the combined companies. Spectra CEO Greg Ebel will move over to serve as non-executive chairman of the Enbridge board. “The combination of Enbridge and Spectra Energy creates what we believe will be the best, most diversified energy infrastructure company in North America, if not the world,” Ebel said.
Spectra shareholders will get Enbridge shares valued at about $40.33 each, a premium of about 11.5% from Spectra’s closing price Friday. At closing, which the companies expect to be completed by the first quarter of 2017, Enbridge shareholders will hold about 57% of the new company, and Spectra shareholders will hold 43%. Headquarters of the new company will be in Calgary.
The deal comes at a time when natural gas producers and transporters are struggling with low commodity prices even as they are constructing large numbers of new pipelines and extending older ones to accommodate the increased production from shale gas plays. Existing pipelines are especially valuable, considering the costs and regulatory hurdles facing new pipeline construction.
Setbacks
Both Spectra and Enbridge have recently had setbacks in pipeline construction projects. The Massachusetts Supreme Judicial Court ruled that power utilities that would become customers of the Spectra-proposed Access Northeast in New York and New England cannot pass on additional construction costs to customers. In June, a Canadian court blocked Enbridge’s proposed Northern Gateway oil pipeline that was to run from Alberta — home of Canada’s tar sands fields — to terminals on the Pacific Coast.
Enbridge’s 450-acre Superior Terminal at Superior, Wisconsin Source: Enbridge
And just days ago, Enbridge announced it was suspending pursuit of regulatory approval for its proposed $2.6 billion Sandpiper pipeline in Minnesota, citing a drop in projected crude oil production in South Dakota and shifting of customer capacity needs to the Dakota Access line.
The Dakota project is garnering notice because of protests from the Standing Rock Sioux Tribe, which is blocking access to a construction site near the border between the Dakotas. The tribe has filed a lawsuit against the U.S. Army Corps of Engineers for approving the pipeline crossing the Missouri River upstream from the tribe’s reservation. The suit claims that the pipeline threatens both the tribe’s drinking water source and its sacred lands.
Fires — possibly arson — caused an estimated $1 million in damage to Dakota Access construction equipment in Iowa last month.
Spectra is not Enbridge’s first acquisition of the summer. Last month, it announced that it and Marathon Petroleum were investing in Dakota Access, with the two companies acquiring 49% equity interest in the Bakken Pipeline System from Energy Transfer and Sunoco Logistics. Enbridge put up $1.5 billion for its 37% share of the 1,168-mile, $3.78 billion pipeline, which is to run from North Dakota to terminals in Illinois.
CAISO’s Board of Governors last week approved proposed Tariff revisions that will require new renewable resources be capable of providing grid-stability services as a condition for interconnecting with the ISO’s system.
CAISO’s Tariff changes will require new and upgraded renewable resources to be capable of providing reactive power and voltage control. Photo of San Gorgonio Pass Wind Farm source: Wikipedia
While stakeholders largely support the amendments, some market participants contend they don’t go far enough in guaranteeing adequate compensation for what has become an increasingly important service as more intermittent resources link up with the grid.
The proposed revisions follow FERC’s June issuance of Order 827, which requires that all newly interconnecting non-synchronous generators have reactive power capability. Resources undergoing upgrades would also be subject to the new rules.
“We are pleased to now take this next step, in which clean power resources can contribute to the reliability of the grid,” CAISO CEO Steve Berberich said in a statement. “By providing reactive power, these resources are better suited to help us integrate increasing numbers of renewable resources.”
“It’s really good utility practice to require all resources in the fleet to have reactive power,” Keith Johnson, CAISO manager of infrastructure policy and contracts, told board members during an Aug. 31 meeting.
The ISO’s Tariff changes go beyond FERC’s mandate for reactive power capability by adding a provision requiring that non-synchronous resources also provide voltage regulation.
“Maintaining voltage is very important for how we operate in the West,” Johnson said, explaining the ISO’s rationale for the additional requirement. “The incremental cost of [automatic voltage regulation] equipment is very, very minimal.”
Thermal Generators Seek Raise
Although the new requirements had broad support among stakeholders, a disagreement arose over CAISO’s decision not to use this FERC filing to alter its compensation for reactive power — a move that would especially benefit thermal generators that are steadily losing market share to renewables.
Under current ISO practice, any generator that is dispatched down to provide reactive power is paid its opportunity cost for lost energy revenues. Generators want the ISO to implement a new market provision that would compensate them for the capital cost of installing reactive power equipment — effectively creating a capacity payment for providing reactive power service.
CAISO contends that generators can recover those costs through their power purchase agreements, given the West’s continued reliance on bilateral contracts for the provision of capacity. Any additional market mechanism would run the risk of creating double payments for the service, Johnson said.
“Providing reactive power is a service essential to the operation of the grid,” said Brian Theaker, director of market affairs at NRG Energy. “Today’s disappointing decision doesn’t advance that.”
Theaker said that the current compensation structure does not provide “reliable signals” for generating units that require longer-term guarantees to remain financially viable.
“We feel like there’s been an opportunity missed here,” said Carrie Bentley, a consultant representing the Western Power Trading Forum. “The ability to provide reactive power is not free,” she continued, adding that five other organized markets offer compensation for the service.
“It’s not a secret that renewable power is disrupting the [capacity] and energy market — a lot of thermal generation will not be able to remain in the market,” Bentley continued. “How do you provide a market signal strong enough to keep the thermal generation we need.”
“The ISO did talk about compensation and looked at some of the other ISOs and RTOs across the country,” Johnson responded. “When PJM or MISO was formed, there were legacy arrangements for capacity payments for reactive power. We have no such system of capacity payments — we have bilateral contracts.”
Keith Casey, CAISO vice president for market and infrastructure development, said Bentley’s concerns about the ISO’s thermal fleet were “spot on.” He pointed out that the ISO’s new flexible ramping product — which compensates generators for the ability to rapidly respond to intermittent output from renewables — is one effort to reward “needed” generators.
“We just view the reactive power capability as a fundamental requirement,” Casey said. “The capital cost for that capability should be addressed through bilateral contracts.”
EPA has finalized a federal implementation plan for compliance with its Regional Haze Rule for the state, but regulators and at least one generator say they may appeal the decision.
The final rule calls for increased emissions control at three coal-fired plants and three natural gas-fired plants, in addition to a paper mill. One of the plant owners, Entergy, said compliance measures could cost it up to $2 billion and that the company is exploring its options. State environmental officials may also appeal the rule.
Imperial Irrigation District Strikes Net Metering Agreement
Imperial Irrigation District, which generated public backlash after it cut off enrollment in its net metering program earlier this year, will allow as many as 1,300 new rooftop solar customers to sign up for the preferential rate.
The district, which provides electrical service to 150,000 customers, reached a deal with the solar industry and state lawmakers to enable any customers who applied for a solar interconnection permit and received a building permit by April 1 to enroll in the program.
IID struck the compromise in the face of possible passage of legislation that would have expanded the eligibility period to July 19.
Appeals Court Denies Release Of PUC-San Onofre Emails
A state appeals court last week reversed a lower court decision that would have forced the Public Utilities Commission to disclose its communications related to the agency’s settlement with Southern California Edison over the closure of the San Onofre nuclear generating station.
The appellate court sided with the PUC, which argued that the communications involved privileged information regarding a rate case. San Diego attorney Michael Aguirre had sought to release the emails to determine whether Gov. Jerry Brown was party to ex parte, private negotiations between former PUC President Michael Peevey and the utility ahead of the settlement. Peevey, a former SoCalEd executive, stepped down from the commission after the negotiations were revealed.
Though the court denied disclosure, it recommended Aguirre submit his request to the PUC under the state’s Public Records Act and, if denied, take his case directly to the appeals court. Aguirre said he will appeal to the state Supreme Court.
Co-op to Shutter 2 Plants Under Regional Haze Plan
The Tri-State Generation and Transmission Association said it will retire more than 500 MW of coal-fired generation in the next decade in order to comply with the state’s implementation plan for EPA’s Regional Haze Rule.
The electric cooperative said it plans to shutter the 100-MW Nucla Station in Montrose County by 2022, along with the nearby mine that feeds the plant. It also plans to close the 427-MW Unit 1 at the Yampa Project by 2025, although two other units at the site will continue to operate. It said it is more economical to close the units rather than retrofit them to comply with the regulations.
“Tri-State has worked tirelessly to preserve our ability to responsibly use coal to produce reliable and affordable power, which makes the decision to retire a coal-fired generating unit all the more difficult,” the company said. “We are not immune to the challenges that face coal-based electricity across the country.”
The Agency for Energy and the Department of Health and Human Services approved $89.5 million in Energy Assistance Program grants last week for 14 nonprofits and utilities.
The grants are meant to help low-income residents pay electric bills. Among the organizations and municipalities that received multi-million dollar grants, DTE Energy received $17 million and Consumers Energy received $13.2 million. The Salvation Army also received $13.7 million, while TrueNorth Community Services received $15 million.
Regulators Promise Decision On PNM Rate Case by Sept. 28
Dunn
The Public Regulation Commission said it will issue a decision within a month on Public Service Company of New Mexico’s rate-increase request. The PRC’s announcement came after most parties in the case objected to reopening hearings.
PNM proposed a 15.8% rate hike earlier this year to cover its investments in power and energy-efficiency measures. In early August, a PRC hearing examiner recommended a 6% increase, saying PNM hadn’t justified the higher rate.
PRC acting general counsel Michael Smith said that as a result of the nearly “uniform” opposition to holding more hearings, “We are going to make a decision based on the recommended decision that was issued by Carolyn Glick,” the hearing examiner.
Regulator Approves ROW for Southline Transmission Project
Land Commissioner Aubrey Dunn last week gave right-of-way approval to the Southline Transmission Project, a proposed 345-kV double-circuit line that would cross into Arizona. Developers must still submit detailed plans about the exact location of structures and roads associated with the line, along with cultural and biological surveys.
Sponsored by Hunt Power subsidiary Southline Transmission, the line will provide up to 1,000 MW of transmission capacity in both directions and connect with as many as 14 existing substation locations.
OCC Orders Fracking Wells Shut down After Earthquake
A magnitude-5.6 earthquake last week spurred state regulators to order 37 fracking waste disposal wells to shut down over a 725-square-mile area.
The order came from the Corporation Commission’s Oil and Gas Division. Gov. Mary Fallin said the commission is coordinating with well operators around the town of Pawnee and that several buildings in the Pawnee Nation had been rendered uninhabitable by the quake. She also said EPA is assessing the region.
The wells will close within 10 days of the order, according to a schedule the commission says is necessary because scientists have warned that a sudden shutdown could provoke another earthquake. A commission spokesperson said the wells were ordered closed because of the link found by the U.S. Geological Survey between wastewater disposal and the increased number of earthquakes in the region, particularly in the state.
WindWaste, an organization opposed to wind power incentives, estimates that future wind developments could force the state to shell out more than $500 million annually in zero-emissions tax credits by 2019.
The subsidy is set to sunset on Jan. 1, 2021, but WindWaste wants lawmakers to end the credit by July 1, 2017. The next legislative session begins in February.
Representatives of the wind industry say WindWaste’s estimates of $5.2 billion in payouts by 2030 is wildly inflated. It argued that the group based its predictions on the amount of generation in SPP’s interconnection queue, which only has a buildout rate of about 15%, it says.
Developers of Wind Project Withdraw Request for Permit
Developers of the Prevailing Winds project asked state regulators last week to withdraw their application for a permit. The retreat came one week after a raucous, four-hour community meeting near Pierre.
Public Utilities Commission Chair Chris Nelson said the request was “unexpected.” The request came shortly before the commission’s Aug. 30 meeting and could be considered at its Sept. 13 meeting.
Prevailing Winds would produce about 200 MW of electricity. By asking to have its application dismissed without prejudice, developers could again apply for a permit at a later date.
The Austin City Council last week unanimously approved Austin Energy’s request to redo its residential electric rates, but not before the city-owned utility first dropped a controversial proposal for an increase. Under the revised rate structure, the municipal utility’s 400,000 residential customers would see bills cut by about $62/year.
The council also signed off on $42.5 million in annual cuts that Austin Energy and its major customers agreed to earlier this month. Most of those cuts will go toward reducing electric bills for industrial and commercial customers. Major customers, such as data centers and large hospitals, will see their electric rates cut 24%.
The utility’s original proposal came under attack because of Austin Energy’s tiered residential price structure: Customers pay the base rate for their first 500 kWh of electricity and higher rates for subsequent blocks of 500 kWh.
SCC Examiner Affirms Right To Third-Party Solar Financing
A State Corporation Commission hearing examiner rejected an argument by Appalachian Power that third-party solar financing was illegal, paving the way for homeowners to sign up for the popular method of paying for residential solar-system installations.
“Today’s decision is an important win for solar rights in Virginia, which has continued to lag behind neighboring states on solar because of outdated policies and utility opposition like we saw from Appalachian Power in this case,” said Will Cleveland, staff attorney at the Southern Environmental Law Center. “The ruling confirms that Virginians have the right to use common sense financial tools to choose solar power without utilities acting as the middle men.”
The utility argued that third-party financing, in which homeowners paid for solar systems through monthly contracts, was legal only under a Dominion Power pilot project. The ruling now goes before the full commission for public comments and final briefs.
The Department of Natural Resources has granted a waterway and wetlands permit for Enbridge Energy to replace a section of old oil pipeline.
Ben Callan, a DNR water management specialist, said the permit is for replacing a 14-mile stretch of Line 3, a 1960s-era pipeline. The pipeline had been operating at a diminished capacity after Enbridge recently found issues during integrity tests. The new section will have a 36-inch diameter and be able to carry up to 760,000 barrels per day.
Callan said that the permit requires the hiring of an independent consultant to oversee compliance. Enbridge spokeswoman Shannon Gustafson said the company has not set a timeline for construction.
ERCOT’s latest resource adequacy assessments indicate it has 25,000 to 30,000 MW of spare generating capacity for the fall and winter.
ERCOT’s control rom Source: ERCOT
The Texas grid operator’s final Seasonal Assessment of Resource Adequacy (SARA) for October and November includes more than 82,000 MW of capacity, more than enough to meet a projected peak demand of about 54,400 MW.
The preliminary winter SARA report is similarly rosy, with more than 81,000 MW of capacity available to meet a forecasted record peak demand just under 59,000 MW. The winter demand record of 57,265 MW was set during February 2011’s record cold.
ERCOT, which operates 90% of the Texas grid, said four gas-fired combustion turbine units and three wind projects have begun operating since its preliminary fall SARA, adding nearly 900 MW of capacity. Three of the gas units are switchable resources and can connect to either ERCOT’s or SPP’s grids. The fall forecast assumes 13,700 to 19,000 MW of planned and unplanned outages.
Another 1,200 MW of new winter-rated capacity is expected to be in service for the winter season (December-February). The final winter SARA report will be released in November.
PJM’s Independent Market Monitor last week gave his blessing to the RTO’s Base Residual Auction for delivery year 2019/20 but called for additional rule changes to build on the tougher standards of Capacity Performance.
The Monitor’s report on the May auction concluded that the results “were competitive, with the caveat that although the Capacity Performance design addressed the most significant issues with the capacity market design, the Capacity Performance design was not fully implemented in the 2019/2020 BRA and there continue to be issues with the capacity market design which have significant consequences for market outcomes.”
PJM will require all capacity to meet CP standards starting with the 2020/21 delivery year.
The Monitor called for additional changes concerning the treatment of pseudo-tied generation, demand response and energy efficiency; the calculation of net revenues; and the application of the minimum offer price rule (MOPR).
The Monitor also acknowledged that its call for using the lower of the cost- or price‐based offer in the calculation of net revenues was rejected by FERC in June (EL14-94-001, ER16-1291). (See “FERC Won’t Revisit Cost-Based Energy Offer Cap Ruling,” PJM News Briefs from FERC Open Meeting.)
But he said the FERC-approved approach used in the May auction, which always uses the cost‐based offer, “resulted in an increase of [$43.4 million], or 0.6%, in the cost of capacity in the 2019/20 BRA.”
In addition, the Monitor recommended:
All costs incurred as a result of a pseudo-tied generator be borne by the unit and included in its capacity market offers.
The “electrical proximity” of pseudo-tied resources be “explicitly accounted for” when defining how external resources should be treated during performance assessment hours.
Enforcing “a consistent definition” of capacity resource as a physical resource at the time of the auctions — with a commitment to be physical in the delivery year and moving all DR to the demand side of the market. The Monitor referenced its 2013 report on replacement capacity, in which it warned that “speculative” DR can suppress prices in the BRA and displace physical generation: “Under the current application of the rules, DR providers may not have identified customers, may not have clear plans for implementing DR measures and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year. This is not consistent with the rules.”
Ensuring the net revenue calculation used to establish the net cost of new entry “reflect the actual flexibility of units in responding to price signals rather than using assumed fixed operating blocks that are not a result of actual unit limitations.” Reflecting actual flexibility will result in higher net revenues, which affect the demand curve and market outcomes, the Monitor said.
Eliminating the rule requiring that small proposed increases in the capability of a generator be treated as planned for purposes of mitigation and exempted from offer capping.
Changing the MOPR review to require all projects use the same modeling assumptions. “That is the only way to ensure that projects compete on the basis of actual costs rather than on the basis of modeling assumptions,” the Monitor said.
Extending the MOPR to existing units in addition to new units.
Re-evaluating the market mitigation exemption granted DR and energy efficiency resources in 2009. “In 2009, there was one product defined for capacity, and there were no resource constraints defined,” the Monitor said. “Particularly in [locational deliverability areas] with few suppliers, there is now the potential for DR and EE providers to exercise market power and affect the clearing price.”
Changing the RPM solution methodology to explicitly incorporate the cost of make-whole payments in the objective function.
Removing energy efficiency resources from the supply side of the capacity market to reflect the change in PJM’s load forecasts. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.) “If EE is not included on the supply side, there is no reason to have an add-back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”
FERC on Wednesday rejected Algonquin Gas Transmission’s request to exempt gas-fired generators from competitive bidding under capacity release rules, another blow to those seeking to increase New England’s gas infrastructure (RP16-618).
Photo credit: Steve Oehlenschlager
The proposal to amend Algonquin’s tariff was an offshoot of the company’s proposed Access Northeast pipeline. Electric distribution companies Eversource Energy and National Grid — which are partnering with Algonquin on the pipeline — sought the exemption to ensure the capacity they purchased would be used to fuel gas-fired generators.
The EDCs hoped to release capacity to gas generators as prearranged “replacement” shippers. FERC rules allow such preferences as long as the replacement shipper matches the highest bid submitted by any other bidder. The proposal would have limited that bidding to gas-fired generators, excluding those who might value the fuel more for winter heating.
The proposal was opposed by numerous merchant generators, including NextEra Energy, Exelon and Calpine, which said they had found cheaper alternatives to ensure fuel supplies under ISO-NE’s Pay-for-Performance capacity incentives, including installation of dual-fuel capacity and contracts with natural gas marketers and LNG suppliers.
“Merchant generators are not asking you for this capacity, and you need to ask yourself why,” Calpine told FERC. The company estimated firm capacity would cost it $25 million annually, or half a billion dollars over a 20-year commitment. It said it could guarantee the same level of service by investing $50 million in a fuel oil tank.
Other opponents argued that the proposal was premature because no state had approved a state-regulated electric reliability program.
“Neither Eversource nor National Grid provided a persuasive explanation for why the ability to release capacity to a prearranged replacement shipper under our existing regulations is not sufficient to meet their needs,” FERC ruled. “Moreover, neither party sufficiently explained why a generator that needed the capacity to obtain the natural gas supplies necessary to generate electricity during a period when Algonquin’s capacity is constrained would not match a higher bid.”
However, the commission said its ruling was “without prejudice to Algonquin developing other more targeted, justified proposals for consideration.”
The commission also granted Algonquin’s request to exempt from bidding an EDC’s capacity release to third parties managing capacity on an EDC’s behalf.
“By permitting capacity holders to use third-party experts to manage their natural gas supply arrangements and their pipeline capacity, [asset management arrangements] provide for lower gas supply costs and more efficient use of the pipeline grid,” the commission said. A compliance filing on this proposal is due in 30 days.
Access Northeast suffered a setback in August when the Massachusetts Supreme Judicial Court overruled state regulators’ order to allow construction costs be assessed to electricity ratepayers. Soon after the ruling, the EDCs withdrew their proposed contracts that were pending before the Massachusetts Department of Public Utilities. (See Eversource, National Grid Withdraw Requests to Bill for Pipeline.)
Access Northeast Complaint Dismissed
In a related case, FERC dismissed a complaint filed by electric generators seeking to block EDC contracts with pipeline owners as premature (EL16-93).
“The circumstances giving rise to the complaint are in a state of flux and the commission does not have before it the concrete facts necessary to determine whether the tariff will be unjust and unreasonable. Several critical project elements of the individual states’ electric reliability programs are undetermined at this time,” FERC wrote.
The commission cited the Massachusetts court ruling, its concurrent order on capacity releases and its pending ruling on Access Northeast, which is expected in the fourth quarter.
The newly established Western Energy Imbalance Market (EIM) governing body kicked off its first meeting last week by electing its leadership.
CAISO’s Board of Governors appointed the five-member body in June, selecting one each from five industry sectors: EIM entities, ISO-participating transmission owners, power suppliers and marketers, publicly owned utilities and state regulators. (See CAISO Board Appoints Western Energy Imbalance Market Governing Body.)
Kristine Schmidt, president of Dallas-based Swan Consulting, was selected to serve as the body’s chair. A former vice president at ITC Holdings and director at Xcel Energy, Schmidt has more than 30 years’ experience in the energy sector. She also worked as an adviser to former FERC Commissioner Nora Brownell.
The EIM Governing Body selected Kristine Schmidt and Doug Howe as its chair and vice-chair, respectively.
Doug Howe, an independent consultant and Ph.D. in mathematics, was chosen as vice chair. Howe has authored or co-authored more than 30 papers and presentations covering industry topics such as energy efficiency in the European Union and utility regulation in the U.K. He previously held an executive position with GPU Inc., which was acquired by FirstEnergy in 2001.
Carl Linvill, a member of the governing body, praised Schmidt for her “equanimity” and also expressed support for the wider Western regional representation that Howe — a New Mexico resident and former state regulator — will provide.
“We still have a lot to figure out and learn,” Linvill said. “Figuring out how to establish a regional presence really is emboldened and enabled by these two positions.”
“On behalf of the ISO, we want to give you our immense thanks for being willing to serve on this body,” CAISO CEO Steve Berberich said. “We consider the EIM as a critical attribute and will continue to support it for as long as necessary.”
A decade ago, Schmidt noted, nobody in the industry would’ve believed the region would have an EIM.
“We’re now seeing a regional market take shape in the West,” Schmidt said. “We’re hitting the ground running.”
Stakeholder Coordination
The governing body’s inaugural meeting included a set of briefings by EIM stakeholders and ISO staff to acquaint members with key structures affecting the market.
“There’s a lot of interest in what you’ll be doing,” said Tony Braun, an industry consultant who chairs the Regional Issues Forum, a loosely structured stakeholder group created by CAISO to foster broad regional discussion about EIM-related issues.
While the forum’s role “has not been concretely laid out,” the group’s first two meetings have been well attended, indicating a high level of interest in the EIM’s activities, Braun said.
The two most significant issues for forum participants: the bidding of external resources at the EIM’s interties and the impact of California’s greenhouse gas regulations on the market. (See related story, CAISO Kicks off Effort to Track GHGs Under Regionalization.)
Braun proposed that future meetings of the forum be coordinated with those of the EIM’s governing body and its state regulators’ group to improve collaboration and reduce participants’ travel for meetings.
“We’d love to hear how we can shape our processes to help you do your jobs,” Braun said.
Governing body members expressed appreciation for the work of the forum.
“The stakeholder-driven nature of the [forum] is probably something that is both difficult and necessary,” said governing body member Valerie Fong. “I found that the way [the meetings are] being run is very open.”
Schmidt called the meetings “extremely helpful.”
“We’re trying to do everything we can do to mitigate some of the travel issues,” she added.
Regulatory Collaboration
Ann Rendahl, chair of the EIM’s body of state regulators, sketched out the role of her group for the new governing body.
“Our purpose is to ensure that state regulators that aren’t involved in this market understand what is going on in EIM,” said Rendahl, a member of the Washington Utilities and Transportation Commission.
The group provides a forum for regulators to learn about EIM and CAISO developments that might be relevant to their jurisdictional responsibilities. While it can take a common position in CAISO and EIM stakeholder processes, individual regulatory commissions are not restricted from taking any position before FERC or the ISO board on EIM-related matters.
The regulators’ group is also charged with monitoring EIM governing body action items and selecting a voting member for the body’s nominating committee.
Rendahl emphasized the need for her group to closely coordinate its activities with that of the governing body. “We want to not just monitor, but work with the governing body,” she said.
ISO Process Basics
Governing body members received a briefing about CAISO’s stakeholder process from Brad Cooper, ISO manager of market design and regulatory policy.
Cooper explained the stakeholder process the ISO uses each fall to develop a “roadmap” of planned policy developments, including EIM initiatives. The ISO last year drew from a catalog of 49 potential initiatives, selecting only 10 because of staff constraints.
“We can’t develop everything in the catalog,” Cooper said.
A final roadmap is presented to the CAISO board — and, in the future, the EIM governing body — at the beginning of each year. The ISO informs stakeholders of any changes to the roadmap through its Market Performance and Planning Forum.
“The roadmap isn’t set in stone,” Cooper said. “For instance, we had the Aliso Canyon issue come up” earlier this year, forcing a modification of the roadmap. (See CAISO Seeks Rapid Response to SoCal Gas Restrictions.)
When developing the roadmap, ISO staff divide initiatives into four categories, including initiatives already in progress, policy changes mandated by FERC, non-discretionary efforts related to reliability or market efficiency, and discretionary initiatives.
For the last category, ISO staff and stakeholders together prioritize potential initiatives according to benefits and feasibility.
“If something could provide great benefits and is relatively trivial to do, that would get priority,” Cooper said.
Cooper acknowledged that CAISO’s policy process is driven more by staff than by stakeholders — and said the ISO prefers it that way.
“We realize that we made a commitment to look at other [stakeholder] processes [to implement under] regionalization, but we think our stakeholder process really allows us to quickly evolve policies,” Cooper said, adding that he didn’t think a project such as the EIM could’ve been developed under a stakeholder-led model.
“The ISO really tries to take a balanced view of our proposed policy,” Cooper said, contending that the ISO’s process does not factor in specific stakeholder interests, avoids “contentious voting structures,” and prevents bias or brokered policy decisions — allowing the ISO to focus on grid reliability.
Still, Cooper emphasized that “stakeholders are involved every step of the way,” including through “working group” meetings that focus on specific initiatives.
“We have a lot of open interaction that may not be possible with more formal stakeholder processes,” Cooper said. “This allows us to really interact with our stakeholders and get their input.”
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