The White House on Thursday announced that President Trump intends to nominate lawyer Kevin McIntyre as chairman of FERC.
The coleader of Jones Day’s energy practice in D.C., McIntyre has represented energy companies in litigation, compliance and enforcement matters and corporate transactions.
McIntyre, who has been rumored for months as Trump’s choice for the chair, would join more than a dozen other Jones Day alumni in the administration, including White House Counsel Don McGahn, a former Jones Day partner. Trump’s campaign reportedly has paid the firm $3.3 million in legal fees since 2015.
The White House said Trump will ask the Senate to confirm McIntyre for the remainder of former Chair Norman Bay’s term, which ends in 2018, and a full term ending in 2023.
McIntyre’s naming would fill the third Republican vacancy on the five-member commission, which could soon be restored to full strength.
Pennsylvania Public Utility Commissioner Robert Powelson and Neil Chatterjee, energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), both Republicans, have already advanced out of the Senate Energy and Natural Resources Committee and are awaiting confirmation votes by the full Senate. Trump has also said he intends to nominate Richard Glick, general counsel for the Democrats on the committee. (See Trump Taps Senate Aide, Former Lobbyist for FERC.)
Trump has yet to officially nominate Glick, however. And Chatterjee and Powelson are on a list of 44 others awaiting a confirmation vote.
The Senate has been mired in its effort to repeal the Affordable Care Act. McConnell on July 11 announced he would delay the chamber’s usual August recess for two weeks to ensure more time to complete action on legislation and nominations.
FERC has been down to one commissioner — acting Chair Cheryl LaFleur — since the departure of Commissioner Colette Honorable at the end of last month. It has been without the necessary three-person quorum since Bay left in February.
Acting FERC Chair Cheryl LaFleur (second from right) will be joined by four new members if Democrat Richard Glick (far right) and Republicans Kevin McIntyre (center), Robert Powelson (far left) and Neil Chatterjee win Senate confirmation.
The Natural Gas Supply Association and the Center for Liquefied Natural Gas released a joint statement praising McIntyre’s nomination but lamenting the amount of time it is taking to restore FERC’s quorum.
“Billions of dollars of investment and thousands of job opportunities in the U.S. continue to be sidelined by a lack of a quorum at FERC,” NGSA CEO Dena Wiggins said. “It is essential that the nominees be given the opportunity to be approved as quickly as possible.”
CLNG Executive Director Charlie Riedl added: “Restoring a quorum at FERC is essential to the LNG approval process, and we hope that Kevin McIntyre and the rest of the nominees will have their floor vote as soon as possible.”
FOLSOM, Calif. — Western Energy Imbalance Market (EIM) leaders last week endorsed a CAISO proposal that would allow the ISO to constrain output from natural gas-fired plants across the EIM in response to potential restrictions on gas deliveries.
The five-member EIM Governing Body voted unanimously to approve applying to the entire EIM footprint the gas constraint developed by CAISO in the Aliso Canyon Gas-Electric Coordination Phase 3 straw proposal. That vote and other advisory decisions will go before the ISO’s Board of Governors later this month.
CAISO originally created the mechanism — which gives the grid operator authority to curtail output from plants in gas-constrained areas — to address reliability worries stemming from the outage at the Aliso Canyon gas storage facility. The latest proposal would extend that authority throughout the footprints of both the ISO and the EIM.
Restrictions on gas withdrawals from the 86-Bcf facility near Los Angeles have created supply concerns for power plants, and there are efforts underway to shut the facility down for good as residents still complain of health problems from the massive gas leak discovered there in October 2015. The California Public Utilities Commission is exploring closing the facility completely. (See Study to Weigh Aliso Canyon Shutdown.)
If FERC approves the plan sanctioned by the EIM body, the market tool will not expire in November as previously planned. CAISO said the tools will be in effect until it completes development of a set of commitment cost and default energy bid enhancements.
Greg Cook, CAISO’s director of market and infrastructure policy, told the body that there are continuing operational risks from the outage at Aliso Canyon. The constraints will address situations in which EIM gas-fired plants have limitations on the amount of gas they can burn in excess of what is scheduled, as well as when generators have limited firm pipeline capacity and additional capacity is not available when gas demand is high.
Governing Body Chair Douglas Howe questioned whether the program could create opportunities for market abuse and whether CAISO’s Department of Market Monitoring supported the measure. The department recently commented that the ISO had not fully justified the plan. (See Qualified Support for CAISO Gas Constraint Plan.)
“How convinced can we be that we won’t be opening up the door to market abuse in the EIM portion” outside CAISO? Howe asked.
There will be a well-vetted market process to make sure there is a legitimate physical constraint and opportunities are not created for market abuse or other unintended consequences, CAISO Vice President of Market and Infrastructure Development Keith Casey told Howe. The tools would only be used to manage physical supply problems on the system, not for economic purposes.
CAISO said it plans to follow a recommendation from the Monitor that it automate the process by which transmission paths are deemed uncompetitive, which triggers the mitigation measures.
The board yesterday also unanimously approved a proposal to include additional gas price indices to be used as a price threshold in the net benefits test, and changes to the board’s charter regarding its interaction with the Regional Issues Forum.
MISO is considering the possibility of factoring transmission constraints into its reserve requirement modeling to help prevent occurrences of scarcity pricing.
Staff are evaluating changing the algorithm underpinning the minimum zonal reserve requirement to reflect energy flow constraints. Under current practice, MISO calculates reserve requirements for a single operating day three days in advance using an offline study to produce results to be posted in time for the day-ahead market.
But actual operating conditions can change from original study assumptions, said MISO Senior Manager of Transmission Security Planning Mike Mattox, adding that the three-day modeling timeline has been in place for about 10 years.
Dhiman Chatterjee, director of market evaluation and design, said a reserve model that does not capture constraints in the interim can unnecessarily create scarcity pricing for reserves.
MISO staff began taking notice of the issue after events occurring April 1, when an offline study predicted an 84-MW minimum contingency reserve requirement for Zone 6, which encompasses Indiana and a slice of Kentucky. In reality, more reserves were needed to compensate for generation and transmission outages in southeast Louisiana, including the shutdown of the Waterford 3 nuclear unit. As a result, Zone 6 experienced an outflow of energy to the south, triggering operating reserve scarcity conditions for 152 five-minute intervals during the day, with spinning and supplemental reserves clearing at about $200/MWh during 131 intervals and $1,100/MWh during 21 intervals.
“We’re really focusing on the event in April. We saw some relatively high prices for the reserves. … In this case, we saw it was bit counterintuitive so we dug into that,” said Chatterjee during a July 13 Market Subcommittee meeting.
MISO Principal Advisor of Market Development and Analysis Yonghong Chen said the constraints can be accounted for in the day-ahead modeling process to address reserve deliverability. Chen said that had the modeling more explicitly accounted for constraints, there would have been more inexpensive prices and a reduction in post-reserve deployment congestion.
“There is really no need to go into scarcity pricing,” Chen said.
Chatterjee said MISO is in the early stages of analyzing an additional modeling step that it could implement by the end of this year or early next year. He said staff would return to the subcommittee next month to update stakeholders on the feasibility of the change.
FOLSOM, Calif. — Energy transfer capacity in the Western Energy Imbalance Market (EIM) footprint is now sufficient to justify removing bid limits that are in effect for members PacifiCorp, NV Energy and Arizona Public Service, CAISO’s internal Market Monitor said last week.
Analysis by the Department of Market Monitoring found that EIM areas are structurally competitive during almost all intervals, Director of Market Monitoring Eric Hildebrandt said July 13 in a briefing to the EIM Governing Body at CAISO headquarters.
The power sellers are now limited to submitting EIM energy bids at or below cost-based default energy bids at all hours. They must get permission for the change from FERC, which requires companies joining the EIM to file for authority to charge market-based rates. PacifiCorp and NVE are both subsidiaries of Warren Buffett’s Berkshire Hathaway Energy.
“We are prepared to submit comments in support of the filing” to lift the restrictions, Hildebrandt said, noting that the Berkshire companies are potentially pivotal in a very small portion of intervals. Automated bid mitigation procedures effectively mitigate market power when imbalance demand is greater than transfer capacity, he said.
Under-mitigation in the 15-minute market, when congestion occurred but bid limits were not triggered as they should have, fell to 1.5% of intervals in the first half of 2017, compared with 17% a year earlier, he said. CAISO’s rules effectively limit the companies’ market power when EIM areas are not competitive.
The companies have been trying to get the mitigation measures lifted. They had argued that the measures imposed by FERC are out of proportion to the market power risks from imbalance energy, because of the small amount of load served by imbalance. They also said they have no incentive to exercise market power because they are large consumers of imbalance energy and would lose money if prices are too high.
But FERC cited market power concerns in May 2016 when it denied a request by NVE and PacifiCorp to rehear a previous decision that prohibited the two companies’ generating units from offering energy into the EIM at prices above default energy bids. (See Berkshire Denied Rehearing on EIM Market Power.)
Growth in EIM Transfer Capacity Has Increased Market Competitiveness, Monitor Says | CAISO Department of Market Monitoring
An economist with the Market Monitor said late last year that increased transfer capacity in the EIM is limiting congestion and reducing participants’ ability to use market power in their balancing authority areas. (See Increased Transfer Capacity Reducing EIM Congestion.)
FERC late last year also denied a request by NVE, PacifiCorp and 19 other Berkshire affiliates to rehear a decision prohibiting the companies from offering power at market-based rates in four neighboring balancing areas in the West, including the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas. The commission rebuffed the companies’ contention that an earlier ruling had denied them due process because it failed to notify them of “newly announced standards” for determining market power. (See FERC Upholds Berkshire Market-Based Rate Ruling.)
The EIM already includes the PACE and PACW areas, while Idaho Power is slated to join the market in April 2018.
ALBANY, N.Y. — The New York Public Service Commission last week approved an indefinite extension for Consolidated Edison’s demand management program in New York City’s Brooklyn and Queens boroughs, which aims to defer an estimated $1 billion in local infrastructure spending.
The commission’s July 13 order retains the original Brooklyn-Queens Demand Management (BQDM) program’s $200 million budget but caps expenditures on utility-side non-traditional solutions — such as storage batteries — at $50 million, including what the company has spent to date.
Con Ed has so far spent $46.56 million on the program, according to the most recent BQDM quarterly report.
The program allots Con Ed $200 million to procure market-based, distributed energy resource solutions such as energy efficiency, energy storage, distributed generation and demand response to achieve load reductions on the sub-transmission feeders supplying the company’s Brownsville No. 1 and No. 2 substations. The program aims at achieving 41 MW of customer-side DER and load reduction, as well as 11 MW of non-traditional utility-side solutions by summer 2018.
“In the absence of the BQDM program to meet the anticipated load growth in that area, Con Edison would have to construct a new distribution substation, a new switching station and substation feeders between the two,” Marco Padula, deputy director for market structure at the state’s Department of Public Service, told the commission. “This major project collectively was projected to cost approximately $1 billion.”
According to Padula, the program has provided Con Ed the flexibility to plan several infrastructure projects to be in service by summer 2019 and further delay the need for the new substation to 2026.
“Specifically, the additional solutions include the installation of capacitor banks, transformers and a 60-MW load transfer to the Glendale network,” Padula said. “With the extension, the company will have the opportunity to procure more DER that will allow it to delay the new substation and defer the need for the Glendale project and also enable possible future deferral for other traditional infrastructure projects.”
Newly appointed commission Chair John B. Rhodes lauded the successful concept design and Con Ed’s successful performance to date in meeting its implementation checkpoints on time and under budget.
“The BQDM program has also provided for important learning opportunities for other utilities, for stakeholders and for the commission, as non-wire alternatives have become part of New York state utilities’ standard business practices,” said Rhodes. “What was new has now become a normal.”
New York City supported the proposed extension in comments filed in April but wanted Con Ed to provide more detail on the cost-effectiveness of non-wire alternatives compared to traditional infrastructure investments. The city raised the possibility of doubling the utility’s incentives for some of the work performed under the program, specifically the Glendale project.
In response, the commission ordered that deferral of the Glendale project must be considered part of the BQDM program — and not as a separate non-wire alternative — that “shall not be eligible for further shareholder incentives beyond what has already been authorized.”
The commission also ordered Con Ed to continue filing quarterly reports and semi-annual cost-benefit analyses on the program, as well as an updated implementation and outreach plan reflecting the new realities inherent in the program’s extension.
The New York Battery & Energy Storage Technology Consortium also filed comments in support of the program, particularly its aspect of broadening the market for DER.
New York-based consultancy Peak Power, however, opposed it, as well as Con Ed’s methodology, load forecasting and auction procurement mechanism. Con Ed replied to all the parties’ comments in May and refuted Peak Power’s criticisms.
The extension order said the commission “does not agree with Peak Power’s characterization of Con Edison’s reporting on the BQDM program as being not transparent or that this proceeding lacks a record to support the company’s proposal.”
Commissioner Diane Burman alluded to criticism of the program but said that “reliability is paramount” and that it’s important to extend the program to avoid losing “the value that we see BQDM is providing.”
“We are seeing more of these [programs] from other utilities looking for similar non-wires alternatives and we’re even starting to see some non-pipes alternatives on the gas side,” Commissioner Greg Sayre added. “We make sure that each program that’s brought to us provides the benefit to ratepayers, compared to the traditional network investment, so we end up with a benefit to ratepayers, to the company and to the environment.”
Central Hudson Recovers REV Costs
The PSC also issued an order last week approving Central Hudson Gas & Electric’s deferral accounting authority and recovery of incremental costs associated with the state’s Reforming the Energy Vision (REV), which requires the state’s utilities to generate 50% of their energy from renewable resources by 2030. The commission’s order authorizes CHG&E to recover more than $1.8 million for incremental external labor costs associated with developing its distributed system implementation plan and related grid modernization efforts.
Michael Worden, DPS director of electric, gas and water, testified that the company incurred the costs as a direct result of commission orders for utilities to integrate DER into their systems and to develop interconnection portals to help facilitate DG interconnection.
“The utilities were also directed by the commission to develop hosting capacity analyses that are intended to identify more technically feasible locations on the distribution system where distributed generation projects could interconnect,” Worden said.
He pointed out that much, if not all, of the work represented in the order would have taken place through the natural process of grid modernization occurring prior to the REV proceeding.
“All of these efforts can be correlated to the increase in distributed resources that’s not only being seen in New York state, but nationally as well,” Worden said.
Burman said she understood “the need for Central Hudson to have regulatory certainty and clarity,” but she noted “that it is potentially cloudy in what it means, what is deemed reasonable and how they will be able to have cost recovery. … I don’t want this to be seen as there’s an unending pot of money for external labor.”
A federal judge on Friday dismissed challenges to Illinois’ zero-emission credit program, saying the customers and independent power producers who filed suit lacked standing and failed to exhaust their remedies at FERC.
Shah | Office of Senator Mark Kirk
U.S. District Court for the Northern District of Illinois Judge Manish S. Shah ruled in favor of motions by the state and Exelon to dismiss the case. “The ZEC program falls within Illinois’s reserved authority over generation facilities. Illinois has sufficiently separated ZECs from wholesale transactions such that the Federal Power Act does not pre-empt the state program,” the judge wrote in a 43-page opinion (17-cv-1163, 17-cv-1164).
The ZECs were authorized by the Future Energy Jobs Act, which the Illinois legislature approved in December after Exelon threatened to close its Clinton and Quad Cities nuclear plants. Following the bill’s signing, Exelon pledged to keep the plants — which it said had lost more than $800 million over the last six years — operating for another 10 years, saving 4,200 direct and secondary jobs.
2 Challenges Combined
The Electric Power Supply Association (EPSA) and members Calpine, Dynegy, Eastern Generation and NRG Energy filed suit in February, saying they stand to lose millions because the subsidized nuclear plants will suppress capacity and energy prices. (See IPPs File Challenge to Illinois Nuclear Subsidies.) The court combined EPSA’s suit with one filed by customers of Exelon’s Commonwealth Edison utility. Exelon intervened in both cases to defend the ZEC program.
On Monday, EPSA and its members filed an appeal with the 7th U.S. Circuit Court of Appeals. NRG spokesman David Gaier said the plaintiffs will ask for an expedited ruling. “If upheld, the Illinois decision would effectively strip FERC of its authority to regulate wholesale markets, would harm ratepayers, and threaten FERC’s ability to drive investment in energy infrastructure,” he said.
Initial briefs are due Aug. 28 under a schedule set by the 7th Circuit on Wednesday. Consolidated briefs are due by Sept. 27 and reply briefs by Oct. 27.
The suits both alleged the ZEC program violates the U.S. Constitution’s dormant Commerce Clause and that it is pre-empted by the Federal Power Act. The consumer plaintiffs also said the ZECs violated the Fourteenth Amendment’s Equal Protection Clause because only Illinois ratepayers will be billed to pay for the subsidy. The court cited an estimate that the ZECs will cost state ratepayers $235 million annually over 10 years.
Illinois modeled the ZECs on renewable energy credit programs enacted by Illinois and most other states, which have not been found to intrude on federal jurisdiction. The Illinois Power Agency will issue ZECs equal to 16% of the electricity delivered by each electric utility to retail customers in the state during calendar year 2014. Retail suppliers are required to purchase the ZECs under 10-year contracts ending May 31, 2027. The price for each ZEC is EPA’s social cost of carbon minus a “price adjustment,” based on energy and capacity prices.
Legal Tests
The Illinois suits raised state-federal jurisdictional issues similar to two cases the Supreme Court ruled on last year. In a January 2016 ruling, the court rejected EPSA’s challenge to FERC Order 745, upholding the commission’s jurisdiction over wholesale market operators’ compensation of demand response. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
EPSA and its members also have filed complaints asking FERC to subject the subsidized nuclear plants to the minimum offer price rule (MOPR) in capacity market auctions.
Plaintiffs’ Standing
In evaluating the motions to dismiss, the court assumed the facts represented by the plaintiffs were true; the case was terminated without any fact finding on the “injuries” the plaintiffs claimed.
To establish the right to sue under Article III of the Constitution, Shah said the plaintiffs must show an “injury in fact” that is “fairly traceable” to Illinois’ conduct and can be fixed by the court. Shah ruled that the plaintiffs lacked Article III standing to challenge the price adjustment, noting Exelon’s observation that eliminating the price adjustment would result in the ZECs being priced at the social cost of carbon. “The injury caused by the ZEC subsidy is not traceable to the price adjustment, because that injury would exist even if the statute were cured of its ties to wholesale auction prices,” Shah ruled.
The judge also ruled the consumers did not have statutory standing for their complaint because the states have authority to regulate retail sales, making the retail surcharge funding the ZECs “outside of the zone of interests of the federal statutes.”
Dormant Commerce Clause
The court was no more sympathetic to the generators’ dormant Commerce Clause claim that the ZECs favor the Clinton and Quad Cities nuclear plants and discriminate against nuclear generators outside the state. “Regardless of whether ZEC recipients are in Illinois or not, the generator plaintiffs’ injury from lower wholesale prices remains the same, and the consumer plaintiffs will receive higher bills,” the judge said. “Since plaintiffs’ injuries are not traceable to the alleged in-state favoritism, they do not have Article III standing to challenge it.”
Clinton nuclear generating station, Illinois
Shah said the validity of dormant Commerce Clause claims “turn on a ‘sensitive, case-by-case analysis’ of the facts, including the ‘purposes and effects’ of the law at issue.”
“Where the statute regulates even-handedly to effectuate a legitimate local public interest, and its effects on interstate commerce are only incidental, it will be upheld unless the burden imposed on such commerce is clearly excessive in relation to the putative local benefits,” he said. “The governor’s and some legislators’ celebratory remarks about the potential job-saving effects of the law do not negate the ZEC program’s environmental purpose and public health interests.”
Pre-emption
The plaintiffs had asked for an injunction to block the ZECs on the grounds that the program is pre-empted by FERC’s authority under the Federal Power Act. Shah ruled the FPA makes FERC responsible for adjudicating such issues and generally does not authorize private causes of action.
“Parties can bring a complaint to FERC if they believe a practice interferes with the markets or creates unjust or unreasonable rates or practices; FERC can take corrective actions to ensure that wholesale rates and practices remain just and reasonable; and parties that disagree with FERC’s decision can seek review in the circuit courts,” Shah said. “A coherent regulatory policy for interstate electricity markets is a desirable outcome, and it is one that private suits undermine.”
He also said the EPSA and Hughes rulings found that “pre-emption applies whenever a tether to wholesale rates is indistinguishable from a direct effect on wholesale rates.”
“The qualifier ‘direct’ is important; influencing the market by subsidizing a participant, without subsidizing the actual wholesale transaction, is indirect and not pre-empted,” he continued. “Since a generator can receive ZECs for producing electricity and the credits are not directly conditioned on clearing wholesale auctions, ZEC payments do not suffer from the ‘fatal defect’ in Hughes.”
Shah also said FERC was equipped to respond to any “market distortion” resulting from the nuclear subsidies. The plaintiffs’ contention that Illinois’ program conflicts with FERC’s preference for competitive auctions is “too broad a theory of pre-emption and would inappropriately limit state authority,” he said.
“So long as FERC can address any problem the ZEC program creates with respect to just and reasonable wholesale rates — and nothing in the complaints suggest that FERC is hobbled in any way by the state statute — there is no conflict,” he said. “The complaint … does not allege that FERC is damaged in its ability to determine just and reasonable rates. The regulatory structure remains unaltered, and FERC’s power undiminished. Consequently, the ZEC program does not conflict with the Federal Power Act.”
Shah’s ruling on this point appears to differ from the Supreme Court’s ruling in Hughes, which said “Maryland cannot regulate in a domain Congress assigned to FERC and then require FERC to accommodate Maryland’s intrusion.” In that case, however, the court ruled that Maryland’s contract for differences subsidy directly and improperly tied the generator’s compensation to PJM capacity market prices.
Equal Protection Claim
Also rejected was the consumers’ complaint that they were being discriminated against because only Illinois ratepayers would fund the ZECs. “The Constitution only requires Illinois to treat equally the people within its jurisdiction. As such, Illinois does not run afoul of the Fourteenth Amendment by treating Illinoisans differently from citizens from other states that live in the MISO or PJM regions,” Shah said. “Furthermore, the complaint does not allege that Illinois could have imposed a surcharge on people in the MISO and PJM regions that lived outside of Illinois.”
The judge noted that courts usually allow plaintiffs to amend a complaint after an initial dismissal. “Here, however, the deficiencies in plaintiffs’ claims cannot be cured with different allegations,” he said. “These plaintiffs cannot pursue the legal theories they have articulated (or they do not have standing to do so). Therefore, I decline to give them leave to amend.”
DENVER — The divisions between SPP’s transmission owners and their customers could not have been starker than they were during the Markets and Operations Policy Committee meeting last week.
Twice, load-serving transmission owners overwhelmingly endorsed voting items favorable to their customers and companies. One was a revision to SPP’s transmission zone placement process. The second was a motion to reject staff’s recommended scope for a high-priority study that didn’t address their concerns with the RTO’s transmission planning process, which they say hasn’t resolved systematic congestion on certain parts of the system.
Both times, the larger number of transmission-using members — 77 of the committee’s 95 voting members — resulted in the TOs coming up on the short end after hours of back-and-forth comments.
“We had a good discussion. I’ll leave it at that,” MOPC Chair Paul Malone, of the Nebraska Public Power District, told the Strategic Planning Committee during its post-MOPC meeting Thursday.
Transmission Planning Process
Large load-serving entities complain that they are footing most of the bill for transmission expansions that also benefit transmission developers, wind developers and small municipal utilities and cooperatives.
Several members questioned the need for the high-priority study of congestion in the Texas Panhandle and western Oklahoma, pointing to recent changes to SPP’s transmission planning process. Staff have streamlined the number of assessments into a single 10-year study that will produce an annual expansion plan addressing reliability, economic and policy needs. The process’s first results will be shared in October 2019. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
A frustrated Greg McAuley of Oklahoma Gas & Electric told the MOPC that while the TOs weren’t in lockstep, they all want to protect customers from additional costs.
“What you see are those that have companies that have to pay for these things are being outvoted. That’s a concern this organization needs to reconsider,” McAuley said. “Our customers have just paid for [transmission planning process] improvements. What I’m hearing today is we’re asking [our customers] to pay another million dollars for another ad hoc study, because our process does not work.”
Transmission Zonal Placement
Kansas City Power & Light’s Denise Buffington, who shepherded the zonal-placement revision request (RR172), tried to take the MOPC’s rejection of her proposal in stride. While waiting for a runner to bring her a microphone during the SPC’s discussion of the proposal, she asked wryly, “Can I just scream?”
Buffington urged board members in attendance to consider adding additional municipalities and cities as members besides the large membership expansions, such as the Integrated System and Mountain West Transmission Group.
“Obviously, the votes that happened at MOPC show those that are paying the bills have less of a vote than those that aren’t paying the bills,” she said. “I encourage you to consider in your strategic-analysis plan all types of membership expansion that affects the pool and members.”
The load-serving TOs approved Buffington’s revision request by a 15-3 margin, with the Basin Electric and Western Farmers cooperatives joining Grand River Dam Authority in opposing it. However, the transmission-using owners voted down the motion 30-12, with seven abstentions, leaving the proposal 11 percentage points short of the necessary 66% approval.
“I just want to put everyone on notice that we will be appealing to the board,” Buffington said immediately after the vote. The Board of Directors and Members Committee meets July 25 in Denver.
“Shocker!” responded Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission and a nay vote.
Buffington has been working on RR172 for two and a half years to address what she says is a gap in the SPP Tariff.
Staff currently determine which of 18 transmission pricing zones to place new TOs in, which can result in cost shifts for those in the incumbent zone. (See SPP Advances KCP&L Cost Shift Proposal.)
The revision request was modified after “robust” stakeholder debate at the SPC and Regional Tariff Working Group, Buffington said. She said the modified RR172 is a “middle ground” and improves transparency in the new member zonal placement decisions by providing advance notice to TOs and their customers, allowing potentially affected entities to provide feedback before SPP makes a decision.
Buffington said RR172 also mitigates costs of zonal-placement decisions and protects both existing and new customers from cost shifts.
“This RR is primarily focused on the cost-shift issue … when SPP creates or expands multi-owner zones,” Buffington said. “KCPL has tried to come up with compromise but hasn’t been able to gain consensus. The alternative is litigation. To me, that’s a lot of risk on both parties.”
Some of those opposing the measure said there wasn’t enough time to study the revisions to the proposal. Others questioned whether the MOPC should be voting on a Tariff change without any working group’s approval. Some cited the “radical new policies” network customers would face in becoming TOs and fears of encroaching on FERC’s rate-setting authority.
“Does this group, as a Markets and Operations Policy Committee, really want to pass a Tariff revision when FERC should be the decision-maker? Rates are in the FERC purview,” said South Central MCN’s Brett Hooton. “We’ve had a lot of long SPC meetings on this topic. I don’t know that rehashing all that is going to change anyone’s opinion today.”
Starnes agreed with Hooton.
“We’ve beaten this horse until it’s bloody and no one recognizes it anymore,” she said, calling for the vote.
FERC staff have approved a MISO proposal to allow generators to withdraw from the RTO’s interconnection queue penalty-free after undergoing a three-stage evaluation process.
The commission’s Office of Energy Market Regulation on Wednesday accepted MISO’s plan in a three-page order containing little comment (ER17-156-003).
In approving MISO’s new interconnection queue rules in January, FERC required the RTO to devise a method to allow refunds of milestone payments if “significant” change affects cumulative network upgrade costs while a project is in the interconnection queue’s definitive planning phase (DPP) — the final phase of the queue before generation interconnection agreements are finalized. The commission also told MISO to define the degree of change needed to trigger a penalty-free exit. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)
Under the new rules, MISO will evaluate cost increases across all three stages of the DPP and assign different thresholds to activate refunds depending on the stage of the project. Refunds will be triggered if:
From the first stage of the DPP to the second, network upgrade costs increase by at least 25% — and a minimum of $10,000/MW — between the publication of the preliminary and revised system impact studies. For upgrades on transmission systems outside of MISO, a 30% cost increase is required.
From the second to third stage, upgrade costs increase by at least 35% — and more than $15,000/MW — between the revised SIS to any phase three studies. For outside transmission system upgrades, a 40% increase is needed.
From the first to the third stage, upgrade costs increase by a cumulative 50% — and at least $20,000/MW — from the preliminary SIS to any phase three studies. Outside transmission system upgrades require a 55% increase.
While acknowledging that the three-step approach was “admittedly more complicated than other solutions,” MISO said it believed the proposal “best balances key interests for both interconnection customers and MISO.”
The gradually increasing thresholds and floors “encourage projects to withdraw earlier in the queue process at a point where restudy is already incorporated in the process and discourages queue gaming,” the RTO said, reducing the need for cascading restudies — a point FERC also asked MISO to address in accepting the new queue rules.
SACRAMENTO, Calif. — A California State Senate bill that would require utilities to obtain 100% of their electricity from zero-carbon sources by the end of 2045 advanced through a key committee in the legislature’s lower house on Wednesday.
The Assembly Utilities and Energy Committee voted 10-4 along party lines to pass SB-100, which the Senate passed on a 25-13 vote in May.
| California Assembly Staff
The bill retains qualifying resources such as wind, solar, geothermal and others currently under the state’s renewable portfolio standard for the first 60% of the requirement, a threshold power sellers must meet by 2030. It does not specify what resources will qualify for the additional 40% target after 2030, except that they be zero carbon. This would keep hydroelectric plants larger than 30 MW in the mix.
Natural gas-fired generation currently accounts for about 36% of California’s electricity mix, followed by renewables (25%), large hydro (10%) and nuclear (9%), according to state data. Imports of coal-fired power still make up about 4% of sales.
While many building trade, renewable energy and public interest groups spoke in favor of the bill at a July 12 hearing at the state capitol, utility representatives complained that their companies will be responsible for dealing with the challenges of implementation.
“None of those stakeholders have all that much skin in the game to how this all actually works,” Southern California Edison lobbyist Ryan Pierini said, adding that utilities are held responsible if blackouts occur. The utility doesn’t oppose the goal but has concerns about the methods of getting there, he said.
A Sacramento Municipal Utilities District representative said the utility does not have a position on the bill, but that transmission constraints will make it difficult to attain. The utility hopes to be granted some “flexibility” in reaching the goal because there are worries over grid reliability and costs.
During the hearing, committee Chairman Chris Holden (D) and Vice Chair Jim Patterson (R) debated the number of jobs and companies leaving California, which Patterson said is losing economic development because of energy costs.
Patterson said that the legislature had not considered the impact on ratepayers struggling with high electricity bills and facing utility cut-offs.
“We are … going full-blown into an area in which we have no definitive information about the costs,” Patterson said.
Holden told Patterson that “we have different perspectives on this issue.”
The bill also requires the California Energy Commission and California Air Resources Board to incorporate the policy into all relevant policies and programs. If passed, the law will oblige those agencies and CAISO to provide legislators with an implementation report every two years beginning Feb. 1, 2019.
California Gov. Jerry Brown and Democratic lawmakers on Monday unveiled a legislative package intended to combat air pollution, including a measure to extend the state’s greenhouse gas (GHG) cap-and-trade program by another 10 years.
Brown | State of California
The proposed legislation modifies and renews the cap-and-trade program, which is due to expire in 2020. The state’s Supreme Court recently declined to review a court challenge against the initiative launched by business groups. (See California High Court Upholds Cap-and-Trade.)
The measures are included in amendments to two bills: AB-617, introduced by State Assemblymembers Cristina Garcia, Eduardo Garcia and Miguel Santiago, and AB-398, sponsored by Eduardo Garcia. It is not clear when a vote might be taken, but Brown’s office has indicated he wants to move quickly.
The program mandates that large industrial facilities such as oil refineries upgrade emissions equipment by December 2023, and it increases penalties for pollution. It also requires pollution reductions from mobile and stationary sources, and provides for neighborhood air monitoring — an attempt to placate environmental justice groups seeking to improve conditions in low-income areas.
The cap-and-trade program will help the state meet its goal of reducing GHG emissions to 40% below 1990 levels by 2030, Brown’s office said in a statement.
The proposed legislation would mandate that California oil refineries upgrade their emissions controls and require pollution reductions from mobile and stationary sources. | photo courtesy of Inhabitat
The new package is “the product of weeks of discussions between the administration and legislative leaders with Republican and Democratic legislators, environmental justice advocates, environmental groups, utilities, industry and labor representatives, economists, agricultural and business organizations, faith leaders and local government officials,” the statement said.
The measure “extends the program by 10 years in the most cost-effective way possible,” according to Brown. It will ensure that carbon pollution will decrease as the emissions cap declines and reduces use of out-of-state carbon offsets, while decreasing free carbon allowances by more than 40% by 2030, he said.
Under the cap-and-trade program, large emitters of greenhouse gases must purchase emissions credits at the California Air Resource Board’s quarterly auctions to cover emissions not accounted for with free credits. Extending the program would keep auction proceeds flowing to environmental initiatives around the state, the governor’s office said.
“To date, these investments have preserved and restored tens of thousands of acres of open space, helped plant thousands of new trees, funded 30,000 energy-efficiency improvements in homes, expanded affordable housing, boosted public transit and helped over 100,000 Californians purchase zero-emission vehicles,” the office said.
Brown said he will continue to pursue climate change policies despite President Trump’s pledge to withdraw from the Paris Agreement on climate change, which Trump says is unfair to the U.S. Brown recently announced that California will host global leaders in September 2018 for a Global Climate Action Summit to support the agreement.
Brown on Wednesday also announced the “America’s Pledge” program with businessman and former New York Mayor Michael Bloomberg. The governor’s office described the program as “a new initiative to compile and quantify the actions of states, cities and businesses in the United States to drive down their greenhouse gas emissions consistent with the goals of the Paris Agreement.” The initiative will produce a report on aggregate climate change commitments by states, cities, business and educational institutions, and a “roadmap for future climate change ambition.”
