FERC has accepted a compliance filing from Entergy on a settlement meant to resolve a more than 20-year-old dispute between the utility and the Louisiana Public Service Commission — a settlement that may or may not be moot.
On Wednesday, FERC accepted Entergy’s revision to make the settlement’s “just and reasonable” standard of review provision applicable to third parties, a change FERC ordered last September (EL00-66-021).
The issue dates to 1995, when the Louisiana PSC and New Orleans City Council filed a successful complaint with FERC, arguing that Entergy’s formula for determining peak load responsibility in its multistate-wide system agreement was unfair because it included interruptible load, in addition to firm load.
The Entergy System used to be more integrated, with Entergy’s operating companies’ transmission and generation facilities operated as a single electric system, and its system agreement consisting of several service schedules that allocated costs among the operating companies according to a responsibility ratio.
After a volley of appeals and remands involving the D.C. Circuit Court of Appeals, FERC ultimately required Entergy to remove all interruptible load from its cost allocation. However, after a series of conflicting rulings, FERC ultimately declined to order refunds, concluding that while the utility failed to have an equitable cost allocation, it did not over-collect. FERC explained that “in a case where the company collected the proper level of revenues, but it is later determined that those revenues should have been allocated differently, the commission traditionally has declined to order refunds.” It also found that “refunds would impose potentially unrecoverable costs” on the Entergy companies.
Entergy said that because the commission’s ruling not to order refunds “render[s] the performance of the settlement agreement moot,” FERC recounted. “Entergy states that the September rehearing order resolved those pending matters and while it is making the requisite compliance filing, the refunds for the 15-month refund period will not be paid.”
But the Louisiana PSC argued that FERC’s decision against refunds is “not a final, non-appealable” order and it’s still possible that refunds could be granted on an appeal the utility filed with the D.C. Circuit last year.
FERC said, however, that the Louisiana appeal was not the issue.
“While the parties hold differing views on the finality of the orders in this proceeding … the issue now before us for decision is whether Entergy’s compliance filing complies with the requirements” of its September order, FERC said.
The U.S. International Trade Commission (ITC) ruled unanimously Friday that increased imports of solar cells and components are harming domestic manufacturers, opening the way for tariffs that critics say could slow solar growth in the U.S.
The vote supporting Suniva and SolarWorld’s claim under Section 201 of the 1974 Trade Act moves the investigation to the remedy phase, which could give President Trump the foundation for implementing his “America First” agenda with tariffs and price floors on some imports.
The ITC said that all four commissioners found that imports of crystalline silicon photovoltaic cells from Mexico account for “a substantial share of total imports and contribute importantly to the serious injury caused by imports.”
The commission also ruled unanimously that imports from South Korea “are a substantial cause of serious injury or threat thereof” and that no significant harm resulted from imports from Australia, Colombia, Jordan, Panama, Peru, Singapore or countries under the U.S.-Dominican Republic-Central America Free Trade Agreement (CAFTA-DR). Three commissioners found no harm from imports from Canada, while Chairman Rhonda K. Schmidtlein did.
A flood of cheap imports has helped create a boom in U.S. solar installations, as total installation costs have fallen almost 70%. For example, in the past two years, National Grid has interconnected more solar than gas-fired generation in New York. (See Renewables Reshaping NY Grid, Policy.)
Worker inspects solar panel at SolarWorld’s Hillsboro, Ore., factory | SolarWorld
SolarWorld Americas CEO Juergen Stein welcomed the ruling as an “important step toward securing relief from a surge of imports that has idled and shuttered dozens of factories, leaving thousands of workers without jobs. … We will continue to invite the Solar Energy Industries Association (SEIA) and our industry partners to work on good solutions for the entire industry.”
Suniva said it filed the complaint “because the U.S. solar manufacturing industry finds itself at the precipice of extinction at the hands of foreign market overcapacity. It will be in President Trump’s hands to decide whether America will continue to have the capability to manufacture this energy source.”
The companies say trade protection would aid domestic manufacturers and compel international makers to move production to the U.S., resulting in more than 100,000 new jobs.
But Friday’s ruling drew condemnation from SEIA and others, who say it will harm the burgeoning industry.
SEIA CEO Abigail Ross Hopper said the ITC’s decision disappoints nearly 9,000 U.S. solar companies and the 260,000 Americans they employ. “Analysts say Suniva’s remedy proposal will double the price of solar, destroy two-thirds of demand, erode billions of dollars in investment and unnecessarily force 88,000 Americans to lose their jobs in 2018,” she said. SEIA represents both companies that manufacture and those that install solar panels.
Suniva panels on roof of Hewlett Packard data center in Georgia | Suniva
“The ITC decision to find injury is disappointing because the facts presented made it clear that the two companies who brought this trade case were injured by their own history of poor business decisions rather than global competition,” said Paul Nathanson, spokesman for the Energy Trade Action Coalition, a group that says it supports “access to freely and fairly traded products” that support American energy industry competitiveness. “The petition is an attempt to recover lost funds for their own financial gain at the expense of the rest of the solar industry.”
Potential Remedy Costs
The commission scheduled a remedy hearing for Oct. 3 and a vote on recommendations to the White House on Oct. 31, with the recommendations to be delivered to the administration by mid-November. The president has 60 days from delivery to decide on what, if any, measures he will take.
The commission could recommend an increase in a duty, imposition of a quota, imposition of a tariff-rate quota (a two-level tariff, under which goods enter at a higher duty after the quota is filled), trade adjustment assistance or a combination of such actions. It could also recommend that the president initiate negotiations with the exporting countries.
The White House said in a statement that Trump’s decision would be based on “the best interests of the United States.” It added that the “U.S. solar manufacturing sector contributes to our energy security and economic prosperity.”
A report by Timothy Fox of ClearView Energy Partners in August said that a commission ruling in favor of the two solar manufacturers could represent an escalation in green trade disputes. “President Donald Trump would likely impose some degree of trade remedies that could undermine the value proposition of new solar projects and may likely reduce solar deployment over the next four years,” Fox said.
The ClearView report calculated that the petition’s proposed 40 cents/W tariff and the proposed price floor of 78 cents/W would raise costs by 60 to 160%.
“President Trump’s general indifference towards renewable power could encourage him to pursue strong trade action,” the report said. “Politically speaking, he may be able to get away with raising the cost of solar products without risking losing many within his base.”
Safeguard Escape Clause
The ITC estimated that nearly 30 U.S. solar panel producers went out of business between 2012 and 2016, the period investigated. During the same period, global imports grew nearly five-fold, a surge led by China, whose imports increased by more than 700%, according to commission figures.
Worker in SolarWorld’s Hillsboro, Ore., factory | SolarWorld
Suniva and SolarWorld filed their petition under Section 201 of the 1974 Trade Act, a rarely invoked article also known as the “safeguard” or “escape” clause.
Global safeguard investigations do not require a finding of an unfair trade practice such as foreign subsidies or dumping. Although safeguard investigations are not country-specific, commissioners who find injury are required to make separate findings for countries with which the U.S. has free-trade agreements, including North American Free Trade Agreement signatories Canada and Mexico and the CAFTA-DR countries (Costa Rica, El Salvador, Guatemala, Honduras, Nicaragua and the Dominican Republic).
SolarWorld said in May that although anti-dumping and anti-subsidy duties have reduced Chinese and Taiwanese imports, global imports have continued to grow. “This surge mainly stems from substantial overcapacity added by Chinese-owned companies that located outside of China to avoid duties,” the company said.
Fox said the most significant distinction of the safeguard petition “is that it moves the final decision-making from agency economic bureaucrats at the [ITC] to White House political staff and President Trump.”
The safeguard authority was last used by President George W. Bush in 2002 to impose a tariff on imported steel. The levy was withdrawn 15 months later after the World Trade Organization ruled that it violated global trading rules.
WASHINGTON — With two new members, FERC commissioners spent much of the commission’s first open meeting since January introducing their teams and new staff members.
They also took the time to thank and praise staff members for their work between Feb. 4, the day after former Chairman Norman Bay resigned, to Aug. 9, when new Chairman Neil Chatterjee and Commissioner Robert Powelson joined to restore the commission’s quorum. During the so-called ‘no quorum period,’ the Office of Energy Market Regulation issued 200 orders under a limited delegated authority. Under the direction of then-acting Chairman Cheryl LaFleur, staff also worked to prepare filings on which they could not act for when a three-member quorum was restored.
Since regaining its quorum, the commission has issued more than 90 orders and rulemakings, including 32 at Wednesday’s meeting. Throughout the meeting, however, Chatterjee and Powelson repeatedly alluded to the massive backlog of filings the commission still needs to act on, which Chatterjee told reporters is his “primary focus” during his tenure.
“As Rob and I were going through the Senate confirmation process, what we heard repeatedly was, ‘We need to get you guys through so we can get FERC working again,’” Chatterjee said. “What has been made clear to me from the moment I walked in the door … is that FERC has been working. It’s been doing tremendous work under acting Chairman LaFleur’s leadership and with the talented efforts of the staff here.”
Powelson said he was “thoroughly impressed with the professionalism and the institutional knowledge and the welcoming spirit” of FERC staff. “You all have been wonderful, and you are what makes this organization tick.”
“Almost makes me feel like we don’t need commissioners when you really see who does the work around here,” LaFleur joked.
LaFleur emphasized the amount of work staff did during the no-quorum period, highlighting the May technical conference on the effects of state policies on wholesale electricity markets; the investigation of potential violations by Energy Transfer Partners regarding its Rover natural gas pipeline in Ohio; and the response to damage at the Oroville Dam in California. (See Local Officials Appeal to FERC as Oroville Water Levels Recede.)
“To say that the first part of this year until my friends arrived was an odd and unusual time at FERC would be an understatement,” LaFleur said. “I always knew our staff had a [strong] work ethic, but it takes tremendous dedication to keep reading things, and writing comments, and writing convoluted memos, and drafting orders when there’s nobody to act on them.”
She also compared FERC’s work on “the big things” during the period — Order 1000, returns on equity, the Public Utility Regulatory Policies Act and hydro licensing — to a duck’s feet underwater: “It moves furiously, but you can’t see it.”
Asked after the meeting whether the commission was waiting on the confirmations of Kevin McIntyre and Richard Glick to tackle these issues, Chatterjee said he would indeed prefer to do that.
“That said, having been through the Senate confirmation process myself, and knowing the uncertainties of that process, certainly we’re prepared to move on some of these major issues if in fact the arrival of our colleagues is delayed in some way,” Chatterjee said. The Senate Energy and Natural Resources Committee forwarded McIntyre’s and Glick’s nominations to the full Senate on Tuesday. (See Senate Panel Clears McIntyre, Glick for FERC.)
But Chatterjee declined to comment on any specific issues or decisions. “I think we tend to go forward on items as they’re ready,” he said. “If they’re ready to go, and we have the votes to approve them … we can move forward.
“I’m optimistic that our colleagues will join us sooner rather than later, but we can’t suspend the commission’s work waiting on the Senate to act.”
Morenoff Feted
Commissioners called out many individual staff members during the meeting, but one name that came up among all three commissioners’ accolades was David Morenoff, FERC’s deputy general counsel.
Morenoff, who has been with the commission since 2006, served as general counsel during the no-quorum period, as well as during the interim period that LaFleur served as chairman after Bay was confirmed.
“Neither of the periods that he was my general counsel were normal,” LaFleur said. “And his superb judgment and support were critical to me personally during both of those times.”
After introducing Morenoff’s replacement, James Danly, Chatterjee said, “I’d be remiss if I didn’t recognize the good work of former General Counsel David Morenoff. I’m grateful for his leadership and willingness to take on this important challenge, and I look forward to continuing to work with him as he returns to his duties as deputy general counsel. David has also been an invaluable resource to me from the moment I walked in the door.”
Toward the end of the meeting, LaFleur — already somewhat emotional from thanking her team for their work during the period — became choked up as she praised Morenoff for leading the Office of General Counsel and the respect he has garnered among its staff.
LaFleur — “with Chairman Chatterjee’s courtesy,” she said — awarded Morenoff the Chairman’s Executive Leadership Award.
FERC on Wednesday approved revised NERC reliability standards on Balancing Authority Control (BAL-005-1) and Facility Interconnection Requirements (FAC-001-3) (RM16-13) and Remedial Action Schemes (PRC-012-2) (RM16-20).
The first order clarifies and consolidates existing frequency control requirements and will result in “more accurate and comprehensive” calculations of reporting area control error (ACE), FERC said. It will require balancing authorities (BAs) to maintain a minimum annual availability of 99.5% for calculating ACE. A BA unable to calculate ACE for more than 30 consecutive minutes must notify its reliability coordinator within 45 minutes of the failure.
NYISO’s control room | NYISO
The second order ensures that remedial action schemes (RAS) do not introduce “unintentional or unacceptable” reliability risks. An RAS is a plan to respond to predetermined system conditions with corrective actions such as adjusting or tripping generation, tripping load or reconfiguring a system to maintain voltages or power flows and avoid cascading system failures.
The new rule requires reliability coordinators to complete reviews of new or modified remedial action schemes before they are placed into service. It also requires planning coordinators to evaluate each scheme within its planning area at least once every five years and mandates an area-wide database of RAS that must be updated annually.
Emergency Preparedness NOPR
The commission also issued a Notice of Proposed Rulemaking (NOPR) that would revise emergency preparedness and operations reliability standards on Event Reporting (EOP-004-4), System Restoration from Blackstart Resources (EOP-005-3), System Restoration Coordination (EOP-006-3) and Loss of Control Center Functionality (EOP-008-2).
The NOPR (RM17-12) is intended to ensure accurate reporting of events to the NERC event analysis group; delineate the roles and responsibilities of entities involved in system restoration processes; and identify the elements required in plans for continuing operations when primary control functionality is lost.
NERC said the revised standards will streamline the current rules and make them more results-based while also addressing concerns the commission expressed in Order 749 regarding system restoration training.
Comments on the NOPR are due 60 days after publication in the Federal Register.
FERC issued seven orders Wednesday revising how MISO deals with its neighbors when incorporating power flows between the RTO and Manitoba Hydro.
The changes affect bidirectional external asynchronous resources (EARs). FERC defines an EAR as “a resource representing an asynchronous DC tie between the synchronous Eastern Interconnection grid and an asynchronous grid that is supported … through dynamic interchange schedules.” Only Manitoba Hydro’s generation currently meets the EAR definition in MISO.
Until 2015, the utility’s hydropower was a dispatchable import into the MISO footprint. In March 2015, however, the RTO and Manitoba began a bidirectional service that allowed the RTO to also export to its northern neighbor.
Slave Falls Generating Station | Manitoba Hydro
MISO said the revisions to the baseline congestion management process align the treatment of export EARs with the treatment of import EARs in the market flow calculations under its congestion management process.
FERC on Wednesday approved revisions, effective June 1, 2017, to:
MISO’s proposed changes followed an August 2015 memorandum of understanding among MISO, PJM and SPP that addressed EARS and other seams coordination issues. The RTO and Manitoba subsequently agreed to amend their Seams Operating Agreement, and MISO received guidance from NERC that resulted in additional proposed changes to the congestion management process.
The revised MISO-SPP JOA creates a process under which MISO will, on request, conduct studies to determine the flowgates impacted by an EAR.
MISO’s revised JOAs with SPP and PJM add an additional notification requirement when an RTO permanently adds or removes a point of interconnection.
The changes to the MISO-PJM JOA also detail other information sharing obligations and align day-ahead energy market coordination and the auction revenue rights/financial transmission rights with market-to-market settlement practices, MISO said.
FERC on Wednesday rejected MISO’s proposed cost allocation plan for interregional projects outside the RTO, saying it had not demonstrated the reasonableness of the methods detailed in the proposal (ER17-387).
Under MISO’s joint operating agreements with PJM and SPP, a transmission project can qualify as interregional even if it is in only one of the two neighboring RTOs, as long as it provides benefits to the other. MISO said that although no such projects are part of its Transmission Expansion Plan, interregional studies currently underway could result in such projects.
Proposal
In its filing last November, the RTO proposed that its portion of costs from an:
Interregional reliability transmission project terminating wholly within SPP or PJM — that is, with no interconnection to any MISO transmission facility — be allocated to those entities who would have paid for the MISO regional transmission projects that the interregional project avoids;
Interregional economic transmission project terminating wholly outside MISO be allocated 100% to the benefiting local resource zones based on adjusted production cost savings (interregional reliability projects terminating wholly within SPP that provide economic benefits to MISO would be allocated in the same manner); and
Interregional public policy transmission projects terminating wholly outside MISO be allocated to parties who would have paid for the MISO regional projects that the interregional project supplants.
The RTO intended to use the method only until the end of its five-year Entergy integration transition period, which ends in December 2018.
In approving Entergy joining MISO, the commission accepted a revised planning and cost allocation framework with two planning areas, one covering the pre-existing MISO members and a new second planning area (MISO South) including Entergy. The RTO said the transition was necessary because transmission planning for the existing MISO footprint and MISO South had not been done under a common process using the same criteria.
FERC rejected MISO’s proposed cost allocation plan for interregional projects outside the RTO, sending the issue back to a divided stakeholder body. | MISO
The transition cost allocation rules, which eliminated MISO’s footprint-wide postage-stamp method, are spelled out in Attachment FF-6 of the the RTO’s Tariff.
The RTO said that without the changes it proposed in November, interregional transmission projects wholly outside the MISO footprint would be allocated under Attachment FF. The costs of an interregional economic transmission project that terminates wholly outside of MISO would use the non-transition market efficiency project cost allocation: 80% to the benefiting zone, 20% postage stamp across the entire MISO footprint. The RTO said that would violate the intent of Attachment FF-6.
FERC Misgivings
FERC first indicated its misgivings with the proposal in a deficiency letter in January, which asked MISO to explain why it was just and reasonable to apply different cost allocation methods based solely on the location of the interregional project.
But the commission ruled that the RTO failed to demonstrate that its proposal would allocate costs in a way “that is at least roughly commensurate with the benefits received.”
“Notwithstanding the fact that the commission has determined that both [multi-value projects (MVPs) and market efficiency projects (MEPs)] provide regional benefits and are appropriately cost-allocated regionally, at least in part, MISO proposes to eliminate the regional cost allocation component for its share of market efficiency projects and multi-value projects that terminate wholly outside MISO,” the commission said. “However, MISO provides no evidence or analysis to demonstrate that the benefits of interregional transmission projects that terminate wholly outside MISO … accrue to a more narrow range of customers than the benefits of any other multi-value project or market efficiency project, including those that physically cross the seam between MISO and another transmission planning region.”
FERC rejected the RTO’s contention that it had previously approved similar cost allocation methods, saying that most of the proceedings cited by the RTO addressed interregional cost allocation methods. “Here, however, MISO is not proposing an interregional cost allocation method; it is proposing regional cost allocation methods that it will use to allocate within MISO the portion of the costs of interregional transmission projects.”
FERC said that although it has approved avoided-cost-only interregional cost allocation methods and an avoided-cost-only regional cost allocation method for reliability projects, “the commission has not previously addressed whether a transmission planning region may use an avoided-cost-only regional cost allocation method for public policy-related transmission projects.”
“This is consistent with the commission’s previous explanation that because Order No. 1000 has different requirements for regional transmission planning and interregional transmission coordination, a just and reasonable interregional cost allocation method may nevertheless be an unjust and unreasonable regional cost allocation method.”
Stakeholders Split
FERC’s rejection means that the issue will return to MISO, where it has divided stakeholders. FERC said the RTO told the commission that if its proposal was rejected, it would not apply the non-transition period cost allocation methods under Attachment FF to interregional projects outside the RTO, “and therefore will have to revisit this issue with its stakeholders.”
MISO told FERC that about half its stakeholders supported the revised Attachment FF-6 while the other half wanted to retain the non-transition period MEP cost allocation in Attachment FF for interregional economic projects entirely outside of the RTO.
Because it rejected MISO’s filing, the commission said it did not have to address protests by the New Orleans City Council, E.ON Climate & Renewables N.A. and EDF Renewable Energy.
The two renewable companies complained about MISO’s criteria requiring MEPs be rated at 345 kV or higher and meet a 1.25:1 benefit-cost ratio, saying they were impeding the development of MEPs. They asked the commission to reject the RTO’s proposal or condition its acceptance on removing the 345-kV threshold and lowering the benefit-cost ratio to 1:1.
New Orleans contended that a MISO analysis had shown that individual transmission owners in benefiting local resource zones may not always receive production cost savings from sub-345-kV economic transmission projects.
The commission also declined to respond to regulators from Arkansas, Louisiana and Mississippi, who sought clarification about which cost allocation methods would apply if the commission rejected the RTO’s proposal.
“MISO states that it will revisit the issue with stakeholders if its proposed cost allocation methods are rejected, and we will afford MISO the opportunity to do so,” the commission said.
FERC on Wednesday approved Exelon’s request for recovery of more than $1.5 million in fuel costs for its natural gas-fired Mystic Generation Station in Everett, Mass. (ER17-933).
The commission order granted Exelon $1,554,854 for Mystic Units 8 and 9 fuel costs that were not recovered because of market power mitigation measures applied last October and November.
ISO-NE’s Internal Market Monitor challenged Exelon’s request for cost recovery for mitigated hours on three days in October 2016, arguing that the company did not adequately provide data in its initial request, and that further supplemental information was submitted past the due date under the RTO’s Tariff.
Mystic Generation Station
“We disagree with the IMM’s position that Exelon’s alleged failure to timely submit information to the IMM for operating days Oct. 1, 3 and 4, 2016, precludes Exelon from seeking additional cost recovery for those days,” the commission said in response. “We do not find that failure to meet that deadline alone necessarily operates as a procedural bar to submitting a [Federal Power Act] Section 205 filing for additional cost recovery or renders such a filing unjust and unreasonable.” It noted that Exelon’s initial filing was submitted on time and that the Monitor did not dispute that certain required information was unavailable to the company at the time.
Exelon also asked to recover nearly $57,000 in regulatory costs in connection with its filing, as well as additional regulatory costs it might incur in connection with the proceeding after the date of its filing. The commission granted this request subject to a compliance filing due in 60 days that details the total regulatory costs.
CAISO’s Board of Governors on Tuesday unanimously approved rule changes that would allow market participants to partake in a program that models generator outages and the impact of remedial action schemes (RAS) on market operations.
During a presentation to the board, CAISO Director of Market and Infrastructure Policy Greg Cook said “stakeholders are generally supportive of the proposal” — but some still worry about unintended consequences.
The board’s vote greenlights modeling of generator contingencies and RAS in the day-ahead and real-time markets, as well as the congestion revenue rights allocation process, but the package still requires approval by FERC.
CAISO’s current modeling only addresses situations in which a transmission line goes down, potentially causing overflow on other lines. The new generator modeling reflects how the system will react to the loss of generation and is meant to ensure that transmission lines are not overwhelmed as the system picks up to address the unexpected shutdown of a generator.
RAS are protective processes that automatically disconnect generators or load to prevent transmission line overload in the event that another line goes out. The new method will update the ISO’s security constrained economic dispatch by modeling the loss of generation within the dispatch, as well as modeling the loss of transmission and generation because of RAS operations. The ISO currently uses manual, out-of-market dispatches to manage generator contingencies.
The changes will alter the congestion component of LMPs so that they consider the cost of positioning the system to account for generator contingencies and RAS operations. A RAS-connected generator does not increase congestion and will potentially receive higher energy prices than other generators at the same bus.
The Western Energy Imbalance Market (EIM) Governing Body on Sept. 6 approved the rule changes for generators that are within the EIM but outside the ISO. (See EIM Body Approves Generator Loss Modeling Plan.) Body Chairman Doug Howe on Tuesday urged the CAISO board to carefully implement the proposal.
Howe said the change will increase the efficiency of the real-time market across the EIM, improve dispatch and lead to more accurate market prices. But he also urged the ISO to ensure the new rule doesn’t create market abuse or too much complexity.
Southern California Edison raised concerns that the program would create a new value stream that could incentivize participants to pursue RAS rather than building new transmission. A company representative questioned whether generators on RAS should be rewarded with higher locational prices.
Trying to value RAS resources “gives us pause,” and the implementation should be carefully monitored, said SCE Director of State Legislative Policy Catherine Hackney. SCE has thousands of megawatts of generation under RAS.
“We need to be vigilant about watching and being wary and being able to respond if things don’t go exactly how we like,” Hackney said.
When it unveiled the proposal in May 2016, CAISO said it had more than 20 RAS modeled within its own system, with more throughout the Western Interconnection. (See Stakeholders Wary of CAISO Contingency Modeling.) The ISO currently factors RAS into its market operations through adjustments to its market software but views that approach as inadequate.
FERC on Wednesday rejected an argument by the California Public Utilities Commission that it erred last year in allowing Pacific Gas and Electric to include a 50-basis-point ISO participation adder in the utility’s 2017 transmission rates proposal.
The PUC filed its protest last November after FERC conditionally accepted PG&E’s proposed rate increase while at the same time denying the PUC’s request to throw out the adder, calling it a $30 million “unjustified windfall” at the expense of California ratepayers. (See CPUC Contest ISO Incentive for PG&E.) The Sacramento Municipal Utility District joined the protest.
The PUC at the time contended that the ruling ignored “the need to demonstrate that an incentive must be ‘justified’ pursuant to [FERC] Order 679,” which allows transmission owners to collect the adder as motivation to join an RTO or ISO. Because the PUC requires California’s investor-owned utilities to be members of CAISO, PG&E did not warrant incentive treatment, the PUC said.
The commission’s Sept. 20 order rebuffed that argument, saying that the PUC had raised the same argument more than 10 years ago in its rehearing request of Order 679, which was rejected in a follow-up order (ER16-2320).
Pacific Gas and Electric transmission lines | PGE
“If the CPUC disagreed with the commission’s determination in Order No. 679-A, the appropriate course of action was to seek judicial review of Order Nos. 679 and 679-A under Section 313 of the” Federal Power Act, FERC said. “The commission has also already held that arguments opposing the granting of an incentive adder for RTO membership to existing RTO members constitute a collateral attack on Order No. 679-A, and we find that the CPUC’s assertion here is in the same vein and warrants the same response.”
The commission also rejected the PUC’s contention that FERC erred by granting the 50-basis-point adder without weighing the specific facts of the case and considering whether a different incentive might be more appropriate. The PUC noted that FERC’s September 2016 order had subjected PG&E’s final return on equity to a hearing by a settlement judge. (See FERC Sets PG&E Rate Increase Proposal for Talks.)
FERC said it approved the adder subject to it being it being applied to a base ROE that left the full ROE within the “zone of reasonableness” determined by the settlement judge.
“Thus, the commission’s duty to ensure just and reasonable rates for consumers will be fulfilled via the trial-type evidentiary hearing process we have ordered, which will result in an ROE, including the proposed adder, that must fall within the zone of reasonableness, and that trial-type evidentiary hearing process is one in which the CPUC may participate,” FERC said.
FERC also said it was “not persuaded” by the PUC’s contention that PG&E’s continued membership in CAISO is not voluntary. It noted that FERC Order 2000 spelled out that voluntary membership was the “most appropriate” approach for creating and expanding RTOs and ISOs.
“This longstanding commission policy of voluntary RTO/ISO formation and membership remains unchanged,” FERC said. “This longstanding commission policy is also reflected in CAISO’s currently effective Transmission Control Agreement, which is on file with the commission.”
SARATOGA SPRINGS, N.Y. — Refurbishing an existing combined-cycle plant can squeeze an extra 12 to 15 MW of generating capacity from each gas turbine — and the compelling economics of equipment upgrades provide New York generators a choice beyond building new plants.
That was the view of Bob Prantil, executive director of sales and strategic accounts for GE Power North America, who spoke Sept. 14 at the fall conference of the Independent Power Producers of New York.
“After all the debates and discussions, eventually electrons need to be placed on a grid at the lowest LCOE [levelized cost of electricity] to make sure that whoever is providing those electrons can break even,” Prantil said. “We recently combined our power business with our grid business because that’s what the market wanted. When you’re going to speak to a utility, it’s not just necessarily about generation. You have to figure out how to get those electrons around.”
Existing Versus New Generation
While New York has a goal of getting 50% of its electricity from renewable resources by 2030, Prantil pointed out that other states are looking at more. Iowa, for example, aims to reach 100% renewable energy over the next five years.
“You all know the complexity of new generation from the standpoint of permitting and do people want it in their backyards — and the construction, where it makes sense,” Prantil said. “I would just challenge you to understand the existing generation that you have in-state already and what [original equipment manufacturers] can do to reduce overall CO2 emissions, gain more efficiency and get more output from those plants at a quarter of the price of a new plant being built.”
Energy conferences these days focus more on renewables and efficiency than on gas, which strikes Prantil as odd.
“Especially in the northeast United States, if you see what’s going on in PJM, there has been an uptick in the installation of combined cycle plants,” he said. “If you think about the sizes of gas turbines now and the efficiencies of those turbines compared to just 10 years ago, it makes the decision to go with gas, as some people call it, a bridge fuel before 100% renewables, a very smart decision.”
GE Power’s 9HA.01 gas turbine helped the company earn a Guinness World Records™ title for powering the world’s most efficient combined-cycle power plant in Bouchain, France. | GE Power
GE Power just set a world record with the company’s first plant in France. Prantil said the combined cycle unit is 99.95% available and achieved a record-setting 62.6% thermal efficiency, 5 percentage points higher than the best combined cycle plants could have achieved just five years ago.
“If you take that efficiency over the life cycle of a plant and then you look at the LCOE for that, and you think about the saved BTUs and CO2, it’s a pretty compelling story,” Prantil said.
Energy Storage and Hybrids
GE built one of the first battery plants in the U.S. in Schenectady, N.Y. “So we know how to do all this,” Prantil said. “We believe that energy storage prices are going to come down.”
He said California has been doing generation-storage hybrids longer than New York, but instead of trying to figure out how to create new markets — which is what New York is doing — GE is looking at how to take an existing market and apply battery technology to it. He cited a case in California where GE applied storage technology to the famed “duck curve.”
“That power needs to be instantaneous, almost like spinning reserve,” Prantil said. “So if you take a 50-MW gas turbine that takes eight or nine minutes to ramp up to speed … you put in a four-hour battery that’s being charged by the grid. We can have the battery take over for the seven minutes of ramping.”
GE sees energy storage as a very cost-effective way to meet some of the ancillary requirements of RTOs and ISOs — and there has to be an ancillary service for any developer to do it and get paid.
GE workers with GE 9HA.01 gas turbine at factory in Belfort, France | GE Power
“We always want to get the EEI [Edison Electric Institute] award for a 1,200-MW combined cycle plant or some offshore wind farm, but we got the EEI award for a 15-MW battery hybrid system,” Prantil said.
Energy efficiency is also driving changes to the dispatch stack, which will also occur in NYISO, he said.
“A developer will look at what zone they’re in, and if there’s a combined cycle plant in that zone, they want to know the efficiency of that plant. And if a generator can build a more efficient plant in that zone, or increase the efficiency of an existing plant, their capacity is more likely to get dispatched.”
New York Native
A native New Yorker schooled in Brooklyn, Queens and the Bronx, Prantil said GE is also a native of the state.
“The headquarters of our GE Power business from the very beginning, from the Thomas Edison years, is located 20 miles from here in Schenectady,” he said.
Prantil noted that GE technology has outfitted about half the state’s nuclear fleet and wind farms, as well as providing 152 gas turbine units and 116 steam and hydro turbine units.
“We like to say that New York is powered by GE, as 60% of the megawatts generated in New York comes from GE equipment,” Prantil said. “We have 152 gas turbine units, we have 116 turbine units, half of the nuclear fleet is with GE technology and about 50% of the installed blades in wind is with GE technology.”
If New York decides to go heavily into offshore wind, GE’s not going to debate if that’s right or wrong, he said, but will instead figure out how to develop the resources at the lowest cost.
