The closure of four nuclear plants in Pennsylvania and Ohio would result in substantial increases in electricity bills and carbon dioxide emissions, among other air pollutants, while cutting jobs and economic productivity, according to a Brattle Group report released on Monday.
The report, commissioned by Nuclear Matters, a bipartisan pro-nuclear advocacy group, focuses on the Three Mile Island unit Exelon said last year it will close and the three plants FirstEnergy Solutions announced on March 28 it was closing: Davis-Besse and Perry in Ohio and Beaver Valley in Pennsylvania. (See FES Seeks Bankruptcy, DOE Emergency Order.)
The closures would trigger price increases of up to $2.43/MWh for Ohioans and $1.77/MWh for Pennsylvanians and eliminate the environmental benefit of all the zero-emissions generation installed in PJM over the past 25 years, according to the report. The four plants’ 4,745 MW generated 38.7 MWh of electricity in 2017, surpassing the 35 million MWh generated by wind, solar, and hydro resources in PJM, the report concluded. It would take 14 years for zero-emissions generation to recover to its 2017 level, Brattle said.
“This means that the retirement of these four nuclear generators would more than undo the entire emissions benefits of all renewable generation investments made to date throughout the PJM region,” the report concluded.
Matching the emissions-free output expected in PJM at the current pace would require another two years and doubling the current growth of generation from renewables to 4.8 million MWh annually. Attempting to replace the environmental benefits of the four nuclear plants with renewables could cost around $2 billion annually, based on the Energy Information Administration’s (EIA) national average renewable cost estimates and would not stop the lost capacity from the nuclear closures being replaced by fossil-fuel generation. “We estimate that about 72% of the replacement would come from gas-fired generation and 28% from coal,” the report said.
The graph shows that replacing the emissions-free generation of the four nuclear plants currently slated for closure in PJM would take 14 years. Matching the emissions-free output expected in PJM at the current trajectory would require doubling the current deployment rate of renewables and another two years. | The Brattle Group
“Following [nuclear plant] Vermont Yankee’s shuttering in New England, we saw devastating effects. The loss of tax revenues forced local officials to make major budget concessions to the detriment of their residents, including cutting their municipal budget by 20%, drastically reducing police services, and raising their property taxes by 20%,” said Judd Gregg, a Nuclear Matters Advocacy Council member and former Republican senator from New Hampshire. “In the year following the closure, carbon emissions increased by 2.5% due to nuclear energy being replaced by emission-producing sources.”
Annual CO2 emissions would increase by more than 20 million metric tons if the plants closed and could create potential social costs of more than $900 million per year. It also would increase annual emissions of air pollutants such as sulfur dioxide, nitrous oxide, and criteria particulate pollutants by tens of thousands of tons, with potential social costs of $170 million per year.
Electricity bills would increase by $400 million for Ohio residents, $285 million for Pennsylvanians, and $1.5 billion across PJM annually, according to the report, due to increased clearing prices in the capacity and energy markets. At least 3,000 jobs would be “at risk” without including indirect jobs at the plants, and the closures would eliminate tens of millions of dollars in local tax revenues.
Other Voices
David Lochbaum, a nuclear safety engineer with the Union of Concerned Scientists, questioned the study’s economic conclusions, telling the Cleveland Plain Dealer that other plant closures have not led to economic disasters. “The unemployment in the other states is not rampant, despite the permanently shut down reactors. The price of electricity in the other states is not exorbitant, despite the permanently shut down reactors,” he said.
“So, why does Nuclear Matters believe the folks in Ohio and Pennsylvania cannot figure out what folks in other states have figured out?” Lochbaum asked.
Meanwhile, the American Petroleum Institute (API) sent President Trump a letter Friday, urging him to reject FirstEnergy’s request for an emergency order to save the nuclear plants. (See Perry Hints DOE Won’t Grant FES ‘Emergency’ Request.)
“The natural gas industry and the shale revolution are poster children for letting the markets work,” API President Jack Gerard said. “The energy abundance wrought by the shale gas revolution is a prime example of competition at work.”
Gerard said government intervention would jeopardize the “economic benefits delivered to consumers” by natural gas.
[EDITOR’s NOTE: Due to an editing error, an earlier version of this article mischaracterized API position on the FirstEnergy request.]
The Artificial Island (AI) transmission project could change or become unnecessary if the two nuclear plants it’s intended to support are shuttered, but retirement threats by plant owners aren’t sufficient to revise the project, the PJM Board of Managers said last week.
The board made the acknowledgement in response to concerns highlighted by the Delaware Energy Users Group in a March 12 letter. Michael K. Messer, the group’s president, urged the board to re-evaluate and potentially cancel the project following threats by owners of the plants, Exelon and Public Service Enterprise Group (PSEG), to close them. (See Del. Group Seeks to Block Artificial Island Project.)
“I can say with a degree of certainty that the retirement of one or more plants at the Artificial Island site would impact the scope of the transmission project,” PJM CEO Andy Ott, a board member, wrote. “However, at this time, absent announced retirements of either Salem or Hope Creek, the project assumptions remain intact.”
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
Exelon and PSEG have announced that they will cancel future capital investments at the two Salem nuclear units they co-own and shut the plants down if New Jersey doesn’t provide them financial support. The state legislature on Thursday passed a bill that would provide the plants with subsidies costing ratepayers about $300 million per year. (See NJ Lawmakers Pass Nuke Subsidies, Boosted RPS.)
The AI transmission project was developed to address transmission stability problems at Salem and the neighboring Hope Creek unit in southern New Jersey and allow them to operate at full power without a book-size compilation of operating constraints. PJM’s first competitive solicitation under Order 1000, the Artificial Island project has been long mired in controversy. In June, the RTO announced several cost allocation alternatives that would shift much of the $280 million price tag from Delaware ratepayers to those in New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
Ott confirmed Messer’s concerns but said any changes to the project would be considered during the system reliability analysis if either plant submits a deactivation notice. “I agree that the analysis proposed by your letter is analysis that PJM should undertake to determine impact to reliability should a plant announce retirement and subsequently impact the Artificial Island project,” he wrote.
ERCOT’s Board of Directors last week rejected an appeal by small public power distributors seeking a proposed change to the ISO’s Nodal Operating Guide regarding the definition of transmission owners.
The revision request (NOGRR149) exempts municipal distribution service providers without transmission or generation facilities from having to procure designated transmission owner (DTO) services from a third-party provider if their annual peak load is less than 25 MW. ERCOT’s Technical Advisory Committee in February unanimously rebuffed an appeal of an early subcommittee’s rejection of the NOGGR after it had been tabled for more than a year. (See “Members Reject Appeal from Small Municipalities,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)
The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads of 9 to 21 MW as the Texas Public Utility Commission’s staff began to look into the issue. However, the NOGGR has never received a positive vote as it moved through the stakeholder process, being rejected three times and tabled nine times.
“Typically, by the time TAC considers a proposal, it has enough consensus to move the initiative forward,” said the Office of Public Utility Counsel’s Diana Coleman, advocating the TAC’s position during the April 10 board meeting. “All 30 TAC members were there, and it didn’t receive one positive vote.”
Pointing to the unanimous vote against the NOGRR at the TAC, board Chair Craven Crowell said, “This particular appeal doesn’t have any legs under it.”
ERCOT CEO Bill Magness told the board that accepting the appeal would be granting an “overly broad” exemption to as many as 53 eligible systems, which represent about 600 MW of the grid’s load.
“If we get into a load shed situation in the ERCOT system, we’re going to ask for the load shed that we need to solve a reliability problem,” Magness said. “It’s going to be distributed out to the participants in the markets to make it happen. We’re going to solve the reliability problem. … Being a part of the [ERCOT] system has its benefits and obligations, and one of those obligations is to participate in load shed.”
Tom Anson, legal counsel to the municipalities under the Small Public Power Group (SPPG), said his members have not been able to reach an agreement with transmission service providers to be their DTOs. He said the SPPG members faces “hundreds of thousands of dollars” to self-designate as DTOs.
“I know ERCOT is reluctant to grant exemptions, but it’s the cleanest thing to do,” Anson said. “It would conform the ERCOT rules to the reality that these small systems just don’t have enough load or other resources to justify the expenditure of the kinds of money to build the substations or other parts of interconnections — all of which, if done, would not increase ERCOT reliability. They would be spending lots of money, but getting no reliability benefits.”
Anson said he was offering a clean solution to the problem, because SPPG members and the larger transmission providers wouldn’t have to continue looking for market solutions.
“Despite lots of hard work, and some progress, we still don’t have permanent solutions in place for all of them. That’s because there is no instant infrastructure, and ERCOT doesn’t control action of third parties. It’s a clean solution because if we want to pursue other rule revisions, time and effort would be avoided.”
The board denied the appeal by a 12-1 vote, with two members abstaining. Carolyn Shellman, who represents the municipal market segment and serves as CPS Energy’s general counsel, was the lone member to vote in favor of the appeal.
Noting the importance of compliance with operating guides and the rule of law, Shellman struggled to balance that with carving out exemptions for “very small groups of entities … that are doing everything necessary to comply if they can.”
“The small power group has some unusual circumstances that may warrant looking at them differently,” she said. “I’m not in favor of a 25-MW exemption … but we do have a solution that works in the market and recognizes the importance of rules. I hate to reject the appeal and send it to the commission that is obligated to enforce the rules we have. I’d hate for them to be in a position to impose penalties that could be devastating on very small systems.”
The SPPG has 35 days to appeal the board’s action, or it can start an appeal process within the TAC by providing different alternatives or language to resolve the issue.
“These small systems are caught between a rock and a hard place,” Anson said. “We’re open to all creative ideas, and we welcome anyone’s thoughts.”
“TAC is willing and looks forward to working with the SPPG,” Coleman said. “It has indicated some of its alternatives would require additional revision requests. We look forward to getting those resolved.”
Tight Summer Conditions Subject of Conversation
Magness said the ISO sees “tight conditions” this summer, not surprising given the surge of coal-fired plant retirements last year that halved ERCOT’s planning reserve margin to 9.3%, 4 percentage points below its 13.75% target. (See ERCOT: Tight Summer Margins No Cause for Alarm.)
“We see sufficient generation [this summer], based on normal conditions,” Magness said. “We could be tested in abnormal situations, based on the tightness of the system.”
Staff have said they have numerous tools at their disposal to help meet what is expected to be a record summer demand of almost 73 GW, including ancillary services, demand response and generators capable of switching between neighboring grids. ERCOT is also working to remove reliability unit commitment (RUC) capacity from its operating reserve demand curve (ORDC), a move that is expected to result in more accurate scarcity pricing (see below).
Texas PUC Chair DeAnn Walker thanked Magness and staff for moving quickly to revise the ORDC, but she added a word of caution.
“I want to raise awareness that when we have changes like this, sometimes we see changes in market behavior,” she said. “I’m relying on ERCOT, and in particular Beth [Garza, the ERCOT Independent Market Monitor’s director], to be keeping their eyes on market behavior like this, to be sure it stays in line with our expectations.”
Garza, for her part, declined to project what will happen this summer. “We would like to share comparisons and contrasts for the last few years, and let you make your own determinations,” she said during her regular update to the board.
She highlighted recent developments in DC tie activity between ERCOT and its neighbors SPP and Mexico. She noted exports across the ties to Mexico have grown in recent years, while imports from SPP have fallen. The five ties have 1.2 GW of capacity but contribute only 389 MW to ERCOT’s capacity in nonemergency situations.
“That could be good news for the summer,” Garza said.
She said lower prices — and the narrowing price spread between ERCOT and SPP — have contributed to decreased imports to the Texas grid.
ERCOT has received more good news in recent weeks, with three previously mothballed generators notifying that they are returning to operational status:
Talen Energy’s gas-fired Barney Davis 1, effective May 7. Talen had said last year it would retire the unit, which has a summer seasonal rating of 300 MW.
The City of Garland’s Gibbons Creek facility, effective May 17. The 454-MW coal-fired unit was approved for seasonal status last year by the ISO.
Garland’s Spencer Units 4 and 5, effective June 1. The two gas units have a total of 118 MW of capacity.
The plants will add almost 900 MW to the ISO’s summer capacity.
ERCOT Projecting $7.2M Favorable Variance in Net Revenues
Magness told the board that ERCOT is projecting a $7.2 million favorable variance in year-end net revenues, driven by winter weather that pushed up load. Net revenues are $4.3 million over budget through February, thanks to the higher administration fees and a $2.1 million favorable variance in expenditures due to timing differences.
ERCOT also saw above-normal revenue neutrality (RENA) uplift charges and market uplift charges in January, Magness said, stressing that the market is functioning as designed.
RENA charges were $16.57 million, up from $7.18 million in December and $10.46 million in January 2017. Magness said congestion in the real-time market was the main driver, with high prices at one end of the constraint and limits on low prices at the other end pushing up RENA.
Market-based uplift to load in January saw charges totaling $71.78 million, compared to a $9.19 million charge in December and a $33.71 million charge in January 2017. High ancillary service costs for non-spin on Jan. 17 contributed to the increase.
Magness also noted two projects continue to track poorly and will be re-planned within months.
The congestion revenue rights system upgrade has been hampered by significant vendor defects. Magness said the vendor has committed to improving its deliverables, and a new go-live date will be set once the defects are resolved.
Integrating the IT change and configuration management system with the content management system will require more time than originally planned, and the scope was expanded to ensure controls maintain data accuracy. A re-plan is expected to be completed in May.
Consent Agenda Removes RUC Capacity from ORDC
The board unanimously passed its consent agenda, which included an other binding document revision request (OBDRR) that removes RUC capacity from the grid operator’s ORDC.
The change meets the PUC’s directive to remove RUC capacity from the ORDC as part of its project assessing the Texas market’s price formation rules (No. 47199). (See “Commission Directs ERCOT to Revise ORDC,” Marquez to Depart Texas PUC.) Magness said the OBDRR is expected to be implanted by June.
The ORDC creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves. PUC staff recommended removing both RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics.
ERCOT staff said it would take two or three months and $30,000 to $40,000 to make the software changes, an increase from the $15,000 to $25,000 initial estimate. The affected systems include Market Management Systems, data and information products, and analytic data.
The consent agenda included six nodal protocol revision requests (NPRRs), a change to the retail market guide (RMGRR), two changes to the Resource Registration Glossary (RRGRRs) and two system change requests (SCRs):
NPRR854: Allows non-opt-in entity (NOIE) transmission and distribution service providers to submit meter data for NOIE points of delivery, rather than incurring the expense of installing, testing and maintaining an ERCOT-polled settlement meter, resulting in decreased expenses for both the NOIE and ERCOT.
NPRR858: Requires ERCOT to publish all current operating plan (COP) data submitted by generators after confidentiality has expired, a change from the limited subset currently available. The change provides transparency into all intra-hour updates to COP data, as generators can update them at any time and change aggregate information available to the market.
NPRR860: Clarifies certain day-ahead market practices and cleans up protocol language to better match the current implementation, including clarifying 1) the language for offering in three-part supply and ancillary service offers for offline non-spinning reserve in the same hour for day-ahead consideration; 2) the self-commitment treatment of resources with only an ancillary service offer submitted for the day-ahead; and 3) ancillary service offer resubmission rules. Also removes the reference to CRRs being co-optimized in the day-ahead.
NPRR864: Modifies the RUC engine to scale down commitment costs of fast-start resources with less than one-hour starts. Following the change, the RUC engine will recommend slow-start resource commitments only if re-dispatching online resources and market-based self-commitments of fast-start resources will not resolve the reliability issue. With the change in the generation portfolio, market-based commitment decisions could be made much closer to real-time than in the past, allowing more self-commitments to materialize in real time than is reflected in COPs many hours earlier.
NPRR865: Requires ERCOT to publish shift factors for hubs, load zones and DC ties for the real-time market, mimicking the day-ahead market’s current practice and providing more information on the inputs used to calculate pricing aggregations.
NPRR868: Modifies the hub bus and load zone definitions and price calculations to account for the current usage of power flow buses — as opposed to electrical buses — in the day-ahead market and congestion revenue rights auction systems. The rewritten formulas will clarify the scenario when buses are de-energized in contingency analyses and align the protocols with ERCOT systems. (A power flow bus — a collection of points on the system that are electrically connected and have zero impedance between them — is identified dynamically based on the status of transmission equipment. Electrical buses — physical transmission elements that use breakers and switches to connect loads, lines, transformers, generators and related infrastructure — are defined statically.)
RMGRR0150: Clarifies the content and format of the competitive retailer safety net spreadsheet within the market guide and removes Section 9, Appendix A1: Competitive Retailer Safety Net Request, which eliminates conflicts between the appendix and language found in Sections 7.4 (Safety Nets) and 7.10 (Emergency Operating Procedures for Extended Unplanned System Outages).
RRGRR015: Clarifies glossary definitions and detailed descriptions of data fields to help market participants successfully submit their resource asset registration forms (RARFs). The change does not add or delete any data requirements, does not require a revision of the existing RARF form and does not require resubmission of previously submitted data already accepted by ERCOT.
RRGRR016: Provides amplifying direction to RARF users for completion of certain solar data and narrows the data in order to provide solar forecasters with more precise data.
SCR793: Gives transmission service providers access to the same ERCOT-generated status telemetry as the ISO’s operators in monitoring line outages with calculated subsynchronous resonance condition monitoring points.
SCR795: Updates the resource limit calculator’s formula for calculating dispatched generation by including the addition of a predicted five-minute wind ramp (PWRR). The PWRR will be calculated from the intra-hour wind forecast and a configurable factor to capture the forecasted five-minute wind ramp, relieving regulation service’s burden to cover the five-minute gain or loss of generation from variations in wind, and instead dispatch this energy economically.
Texas regulators last week pressed Southwestern Public Service for more details to justify its plan to build 1.23 GW of wind generation even though it doesn’t need the capacity.
The company and parties to a settlement over the project agreed to file additional written comments to its application for construction (Docket No. 46936).
The Texas Public Utility Commission’s staff has issued a conditional approval of the wind farms’ construction, but the commissioners expressed reservations.
“Where I am now, you’re not going to like the answer,” PUC Chair DeAnn Walker told the parties to the agreement during an April 13 open meeting. “The more information you can provide me, the more likely it is you can satisfy the concerns I have.”
D’Andrea questions SPS representatives as Walker listens. | TexasAdmin
Walker raised a number of issues with the parties, the central one being “upon what legal basis” the PUC can grant an application for new generation “when the applicant admits that there is currently sufficient generating capacity on its system to serve its customers?”
SPS announced last year that it intended to build a pair of wind farms in Texas and New Mexico and secure a long-term contract for energy from another facility as part of parent Xcel Energy’s multistate investment in wind. Xcel said the projects are expected to save the region’s customers about $2.8 billion over a 30-year period.
The company said in March it had reached an agreement with commission staff, the International Brotherhood of Electrical Workers and Lea County Electric Cooperative. SPS said nine other parties in the docket do not oppose the company’s request. The State Office of Administrative Hearings has admitted the settlement testimony into the record and remanded the case back to the PUC without holding a hearing.
Commissioner Arthur D’Andrea echoed Walker’s comments, saying he had “strong discomfort” with the deal.
“The fact it’s a settlement makes it more difficult to see what’s going on,” D’Andrea said. “My understanding is that the usual role of the commission is to approve something that looks like a taxing authority. The utility, in return, builds generation. This looks like billions of dollars in taxing authority and in return, the citizens get a wind deal and production tax credits.”
SPS’ David Hudson explains the wind projects to the Texas commissioners. | TexasAdmin
SPS President David Hudson responded that the generation would save ratepayers money through avoided fuel costs from other generation and the production tax credits (PTCs). He said the project qualified for 100% of the PTCs by purchasing wind turbines in 2016.
“PTCs at 100% value are pretty substantial,” Hudson said, noting the rate would be more than 3 cents/kWh after revenue requirement tax calculations. “That’s it automatic flow back to customers as a benefit, plus the avoided fuel costs. So, it’s true, [customers] will be paying the capital cost for the investment and recovery in base rates, but they’ll be getting substantial benefits through … zero-fuel energy and credit for the [PTCs].”
“I appreciate you are being creative,” D’Andrea said. “I’m not trying to say, ‘Spend a half billion on coal plants and improve the scrubbers.’ I wouldn’t want to throw bad money after bad money. I’m a little worried this goes too far. You basically say you don’t need this generation and that this is purely a financial play. That seems to be a strange thing for us to be approving.”
Attorney Rex VanMiddlesworth, representing Texas Industrial Energy Consumers, agreed with D’Andrea that SPS’ application is “unusual” but said that if there’s an “honest broker” in the proceeding, it’s his consumers group.
“Our jaundiced view of the utility is they make money, whether a plant is economical or not,” VanMiddlesworth said. “We want to look at whether this is good for the ratepayers. There’s a lot of risk. What if it goes over budget or doesn’t perform well? We ultimately concluded that this plant was very likely going to save Texas ratepayers hundreds of millions of dollars over its life.”
D’Andrea said he could support the project based on its economics, but that he needed more than a handful of spreadsheets before rendering a decision.
The parties promised to supply the commissioners with additional information in a week. The PUC next meets in open session April 27.
SPS has proposed building a 478-MW wind farm in West Texas and a 522-MW facility in New Mexico, though only the Texas project is part of the proceeding. The company also plans a 30-year power purchase agreement for an additional 230 MW of wind generation from Bonita Wind Energy, a NextEra Energy Resources subsidiary.
PUC Approves Transfer of Bankrupt ExGen’s Assets
The commission also approved the transfer of nearly 3.5 GW of gas-fired power plants from bankrupt merchant generator ExGen Texas Power to its creditors: Fidelity Management & Research, Fortress Credit Advisors, GSO/Blackstone Debt Funds Management, Guggenheim Partners Investment Management, Oppenheimer Funds, PineBridge Investments and Avenue Capital Management.
PUC Chair DeAnn Walker, Commissioner Arthur D’Andrea meet as a two-person commission for the first time. | TexasAdmin
Walker and D’Andrea agreed with staff’s recommendation to approve the transfer, which staff noted would give ExGen and the creditors and affiliates a combined 7.6 GW of capacity, 8.2% of the generation capacity in ERCOT or capable of delivery into the grid (Docket No. 47836).
“As the total combined capacity is below the 20% threshold, necessarily, the capacity owned and controlled by each applicant individually is also below the 20% threshold,” staff wrote.
ExGen, an Exelon subsidiary, filed for Chapter 11 bankruptcy in November, blaming low wholesale prices due to cheap gas and increasing wind production.
The five plants are: Wolf Hollow I, Colorado Bend I, Mountain Creek, LaPort and Handley.
Non-IOUs to be Added to Rate Review Schedule
The commissioners adopted a new rate review schedule for investor-owned utilities and asked staff to include non-IOUs in the same rule (Docket No. 47545).
The rule revision implements the provisions of Texas SB 735.
Staff’s proposal sets a schedule for 10 IOUs, beginning with Texas-New Mexico Power in August and ending with Oncor in October 2021.
In a potential boost for competitive transmission developers, the U.S. Justice Department said Friday that a Minnesota law granting in-state transmission owners a right of first refusal (ROFR) on grid additions is unconstitutional.
The department filed a “Statement of Interest” with the U.S. District Court of Minnesota, supporting a challenge filed in September by LSP Transmission Holdings over a ROFR law approved by Minnesota lawmakers in 2012 (17-cv-04490).
The law gives incumbent TOs a ROFR to build new high-voltage transmission lines that connect to their facilities, effectively preventing new entrants without a physical presence in Minnesota from competing.
“The United States believes that a state law which grants local electricity monopolists the right to obtain new monopolies in transmission projects in interstate commerce, and thereby block entry by potentially out-of-state competitors, unconstitutionally regulates interstate commerce in violation of the dormant Commerce Clause,” Justice Department lawyers wrote.
The Commerce Clause of the Constitution gives Congress the power to regulate interstate commerce. The idea of the “dormant” clause is that it prohibits states from doing the same.
Residents review possible paths of Wilmarth-Huntley transmission line at June 2017 open house. | Xcel Energy
Minnesota approved the law following FERC’s issuance of Order 1000, which required RTOs and ISOs to remove federal ROFRs from their tariffs. FERC said the order was not “intended to limit, pre-empt or otherwise affect state or local laws or regulations with respect to construction of transmission facilities.”
But Justice Department lawyers said that while FERC did not void state ROFRs, “none of FERC’s orders granted states any new authority to create rights of first refusal, or suggested that state rights of first refusal are consistent with the dormant Commerce Clause.”
The state law “fails both the antidiscrimination test and the undue burden test because it raises entry barriers, segments the interstate market in developing transmission lines, favors in-state incumbents and causes substantial anticompetitive effects in interstate commerce,” the department continued.
Xcel Energy’s Northern States Power and ITC Midwestern Holdings, which were awarded rights by MISO to build the 40-mile Huntley-Wilmarth 345-kV line because of the state ROFR, have joined the state in asking for dismissal of the suit.
“ITC continues to support what’s in the best interest of customers as it relates to modernizing a state’s electric transmission infrastructure,” ITC spokesperson Liz Hunt said in response to the Justice Department filing. “ITC is supportive of ROFR in states where there has been a track record of success of transmission and investment by the local or incumbent utilities.” Xcel had no immediate comment.
Huntley-Wilmarth project map | Xcel Energy
The project, estimated at $108 million, will connect Xcel’s existing Wilmarth substation north of Mankato, Minn., and a proposed Huntley substation south of Winnebago, Minn., that will be owned by ITC.
Although the new line is a market efficiency project — a category eligible for competition — MISO declined to open it to competition because of the Minnesota law, a decision backed by FERC.
Northern States Power argued for dismissal of the suit, saying Minnesota’s ROFR “was recognized by the regional planning entity and approved over LSP Transmission’s objection by FERC.”
The Justice Department disagreed. “All FERC found was that ‘it is appropriate for MISO to recognize state or local laws or regulations as a threshold matter in the regional transmission planning process,’” the department said.
“In doing so, FERC simply recognized that requiring FERC-regulated entities to ignore state rights of first refusal would waste time and resources, as the entities’ decision-making process ultimately could be overruled by the state’s right of first refusal,” the Justice Department said.
Sharon Segner, vice president of LS Power Development, who testified against the ROFR bill in a legislative hearing, said her company’s challenge is the first against such state rules. LS Power also has identified ROFRs in North Dakota, South Dakota and Indiana.
WESTBOROUGH, Mass. — The Trump administration’s push to roll back environmental protections has prompted state leaders to recommit to achieving clean energy goals and inspired a surge in grassroots support for measures to tackle climate change, New England environmental and energy experts said last week.
The administration’s “radical agenda on environmental rules has galvanized public opposition,” as well as “created huge morale problems” within EPA, said Melissa Hoffer, chief of the Environmental and Energy Bureau for the Massachusetts attorney general’s office.
Hoffer made her remarks at the Northeast Energy and Commerce Association’s Environmental Conference on Thursday.
Even the Republican-led Congress did not go along with President Trump’s vision to slash EPA’s budget, instead increasing the agency’s funding this year by $760 million, said Normandeau Associates’ Bob Varney, a former EPA regional administrator for New England.
Following the U.S. decision last June to pull out of the Paris Agreement, environmentalists feared a “spiraling ripple effect” discouraging other nations from honoring the pledge to reduce emissions 20 to 26% below 2001 levels, “but that hasn’t happened,” said Ken Kimmell, president of the Union of Concerned Scientists.
The governors of several large states, including California and New York, joined together to commit to honoring the Paris Agreement, supported by mayors and corporate CEOs, which perhaps explains why other nations did not react too negatively to the U.S. pullout, Kimmell said.
Race to the Bottom
Varney noted what EPA calls “‘getting back to basics,’ with a focus on the agency’s core mission, restoring power to the states through cooperative federalism, and improving permitting and clean-up processes while adhering to the rule of law, according to the administrator in his comments.”
But Hoffer said EPA Administrator Scott Pruitt’s “notion of cooperative federalism is somewhat flexible and it invites a deregulatory race to the bottom. This is exactly what the primary federal environmental statutes were designed to avoid.”
Kimmell joked that after the 2016 election, “we changed our name to the Union of Freaking Out Scientists, known as UFO.”
He listed the agency’s big three regulatory rollbacks: the “evisceration” of the Clean Power Plan, the elimination of rules requiring oil and gas operators to trap methane and, “perhaps most distressing of all,” the reduction of the Obama-era fuel economy standards.
Hoffer said the administration’s “cavalier approach to the rollbacks that took place during the first 15 months is really not serving them well in the courts. They actually don’t have a good command of administrative law, and they don’t have a good command of federal environmental statutes, so that has caused some difficulty for them.”
She said, however, that the administration may be learning from its mistakes, as they’ve recruited some new experts. “I would expect that we’ll see their game upped tremendously over the course of the next couple of months,” Hoffer said.
Olivia Campbell Andersen, executive director of Renewable Energy Vermont, said state leadership has proven more significant for the growth of renewable energy than federal policy.
“If it weren’t for state provisions like net metering, if it weren’t for state renewable portfolio standards, we would not have seen the growth that we have had to this point,” she said.
“Climate change is already happening and we’re already seeing the impacts, including hotter days,” said Richard McGuinness, deputy director for waterfront planning at the Boston Planning and Development Agency.
The agency commissioned the Climate Ready Boston initiative focused on climate change, the first citywide plan for Boston in 60 years, he said.
“Heat island effect, extreme precipitation events and sea-level rise are the greatest risks to our coastal communities,” McGuinness said. “We are planning for a 36-inch sea-level rise and rounding it up to 40 inches to account for subsidence … we’re not planning on retreating.”
The worst-case scenario for coastal flooding in Boston would affect 85,000 people and damage 12,000 buildings worth about $85 billion, he said.
Grover Fugate, executive director of the Rhode Island Coastal Resources Management Council, said, “The brunt of climate change effects will fall on local communities, the ones with the least resources to deal with them.”
He complained that the Federal Emergency Management Agency makes planning assumptions that do not match Rhode Island conditions, resulting in post-storm dune profiles larger than the state’s dunes are before any storm. Fugate said his agency bases its sea-level estimates for the year 2100 on data from a 2017 report by the National Oceanic and Atmospheric Administration, which describes sea-level rise scenarios for the U.S.
For the Newport tide gauge, the figure is “essentially 9.6 feet by 2100 or essentially 10 feet,” Fugate said. “We also throw on a high-tide event, extreme high tide, which we see six to eight times a year, that will raise the tidal elevation 1.5 to 2 feet above normal tide, so we now have incorporated a 12-foot layer in our mapping system.”
The sleeper issue is groundwater rise compounded by sea-level rise, causing septic systems to fail and damaging local roads, he said.
“If you build today … potentially, within the 30-year mortgage period, that house will be below base-flood elevation.”
Thomas Murray, vice president for customers and communities at Vermont Gas Systems, said he learned that a large project can be incredibly more complex than a small one, and that it’s important to avoid “utility arrogance” and respect the views of project opponents.
“People see stopping our project [the 41-mile Addison Natural Gas Project] as a symbolic way to stop climate change,” Murray said.
“In fact, what may happen, the unintended consequence, is that they continue to burn dirtier fossil fuel, they continue to burn oil,” Murray said. “Vermont has the smallest natural gas footprint in the country, next to Hawaii, and we have the largest percentage of people that are burning heating oil.”
James Grasso, CEO of public relations firm Grasso Associates, noted that Brookline, Mass., residents voted 61% in favor of legalizing recreational marijuana, but they refused to have it sold in the town.
Emily Norton, chapter director of the Massachusetts Sierra Club, and a member of the Newton, Mass., City Council, said the council voted against solar parking canopies at the public library because the panels were too ugly.
“When people do get involved, they jump right into it, and they don’t understand how state or federal or local laws and regulations work,” said Heidi Ricci, assistant director of advocacy at Mass Audubon. “Most people don’t know where their water comes from when they turn on their tap. I think there’s a basic public education problem here as well as a civic engagement problem.
“People latch on to the one project that they’re concerned about that they oppose … but who’s looking at the big picture?” she said. “I’ve talked with the big gas pipeline opponents about, so, like what are we going to do? Will you work with us on getting some of these offshore wind projects going? It’s really hard to get people engaged in larger-picture planning.”
KANSAS CITY, Mo. — SPP officials were questioned at last week’s Markets and Operations Policy Committee meeting as to why the Holistic Integrated Tariff Team was created and approved behind closed doors in March.
The Board of Directors approved the team’s creation during the same executive session at Dallas/Fort Worth International Airport where it approved a set of policy recommendations to guide the Mountain West Transmission Group’s pending membership into SPP. (See SPP Begins Work of Integrating Mountain West.) Some stakeholders have taken to calling the team the “HITT squad.”
“Some of us didn’t hear the discussion about how the board thinks about this, or how it went about populating it and how the different entities were selected on it,” said The Wind Coalition’s Steve Gaw.
SPP Legal Counsel Paul Suskie, who is serving as the HITT’s staff secretary, said the team’s formation was presented to the board as a recommendation from staff, with the addition of “a couple of other people who could help out.”
“Honestly, it was a matter of getting it moving sooner rather than later,” Suskie said.
The team, comprising directors, regulators, staff and stakeholders, is charged with developing a set of high-level recommendations addressing the challenges facing SPP’s footprint. It is expected to complete its work with a written report by April 2019. (See SPP Team to Take ‘Holistic’ Look at Processes.)
“My point is, this did not need to be done in closed session,” Gaw said. “Stakeholders could have given some input to the board. This is a huge strategic undertaking.”
He said much of the HITT’s work will be dedicated to issues affecting renewable energy and noted that only one of the 16 team members is “related to those particular interests.”
“We would like to have had some degree of feedback to the board in open session,” Gaw said.
“All due respect, Steve, do you really believe we would have started down this road without stakeholder input?” responded SPP Director Julian Brix. “Someone had to make this decision. The board signed on to this because it said it would like a reasonable way to get answers to strategy questions we’ve had for some time. It will be an open process down the road. You’ve got to have a starting point, and this was it.”
SPP Vice President of Engineering Lanny Nickell reminded Gaw and the MOPC that the Strategic Planning Committee discussed creating such a group during a lengthy discussion in January. (See “Energy-only Resources Report Leads to Discussion, not Results,” SPP Strategic Planning Committee Briefs.)
“That’s really where we got started in identifying those interested in participating,” Nickell said.
SPP has proposed that most HITT meetings be held face to face, with stakeholders not on the team “encourage[d]” to participate by dialing in, unless they are presenting to the team in person. Those not on the team are also encouraged to ask questions and suggest future topics for the team to evaluate.
Staff has scheduled nine meetings for the HITT through Dec. 5. Two of those will follow the April and July board meetings, giving non-team members a chance to attend.
KANSAS CITY, Mo. — SPP’s Markets and Operations Policy Committee endorsed a rule change to address member concerns that the Integrated Transmission Planning (ITP) Manual doesn’t appropriately capture purchase power agreement (PPA) pricing in the adjusted production cost-benefit metric.
RR276 removes the PPA pricing from the variable operations and maintenance (VOM) methodology language in the ITP Manual and replaces it with a VOM cost of $0/MWh for all wind and solar units. The Economic Studies Working Group (ESWG) had proposed a VOM cost of $8/MWh but revised the number following stakeholder discussion.
The ESWG said RR276 better captures the “benefits of incremental transmission investment when reducing economic curtailment or congestion costs associated with transmission customer purchases from renewable generation resources under ‘take or pay’ power purchase agreements.”
The MMU said the zero VOM cost is a “much closer reflection” to the actual number based on its review of all mitigated offers resources have applied for in the SPP market.
“We were sort of surprised to see a number that high,” Collins said referencing the $8/MWh proposal. “It does not in any away affect the bottom prices we have on file. Zero is more reflective of the true number.”
The Nebraska Public Power District’s Tim Owens, the ESWG’s vice chair, said the revision request is necessary as the 2019 planning cycle begins. He said it is an interim solution to objections over proxy PPA pricing, and the group will continue to work with staff on improving the economic studies process.
“We are trying to address this one particular input,” Owens said. “We fully understand that this is not the end-all assumption. Setting it to zero or eight won’t in and of itself address all of these other issues. We’re just focusing on what we’re going to do for the 2019 ITP assessment.”
“I see the benefits of a zero VOM, but my major concern is fixing the process,” said Southwestern Public Service’s Bill Grant.
The measure cleared the two-thirds approval threshold at 68.3% in a roll-call vote. Transmission-using members (TUs) voted 36-7 in favor of the revision, overcoming a 9-8 split by transmission owners.
Members Hash out Charter Revisions by Working Groups
Members revised and endorsed a Transmission Working Group (TWG) charter revision to increase its membership, proposing that the group include all TOs and an equal number of TUs.
The TWG had proposed increasing its membership from 24 members to 26, with no more than 14 TOs or TUs at any one time. Several members expressed concerns about the group handling compliance issues without representation of all 17 TOs.
“It’s very important that the votes presented to MOPC are reflective of the full membership, and that MOPC has that guidance when they vote,” Grant said. “You don’t want the unintended consequences because of what that one person could come up with.”
Sunflower Electric Power Cooperative’s Al Tamimi pointed out his company is one of the TOs currently excluded from the TWG. “If I don’t get a seat, I don’t want this group handling compliance matters,” he said.
Other members pushed back against the membership expansion.
“If we’re going to do this for the TWG, what other groups now can be expanding their membership?” asked Oklahoma Gas & Electric’s Greg McAuley. “With the Mountain West coming with another potential 10 TOs, this group is going to be enormous. I don’t know what you’re going to get done.”
TWG Chair Travis Hyde, of OG&E, said the group’s proposal was a compromise as it tried to seat all 17 of the TOs listed under SPP’s bylaws. He said the TWG has tried to maintain a balance between TOs and TUs but has realized its attempt was becoming unwieldy.
“If we did, we’d get to [34],” Hyde said. “That’s too big for a technical group like we are.”
SPP COO Carl Monroe said the RTO’s bylaws require all stakeholder groups to be balanced, “unless your charters are accepted with some other requirement.” He said the organization uses TOs and TUs as “shortcuts,” in the absence of member-type definitions in the bylaws, but recommended the groups change their governing documents if they disagree with the shortcuts.
“You can change the charter, but all these changes have to go through the Corporate Governance Committee,” he said. “If we had half this many people in a room trying to make the decision, we wouldn’t have the issues we do as the MOPC together.”
Kansas City Power & Light’s Denise Buffington, a member of the CGC, clarified Monroe’s comments. “The bylaws don’t explicitly say stakeholder groups should be balanced. That’s just the way it’s always been interpreted,” she said.
The MOPC also endorsed a change to the charter of the Regional Tariff Working Group that gives all TOs representation, with an “up to” equal number of TUs. The RTWG said it has a longstanding policy that all TOs be represented, as their facilities are under SPP’s functional control “for the provision of transmission service, planning, interconnections and recovery of revenue requirements.”
Members did strike a provision that would have limited members with affiliated relationships to a single vote on the RTWG.
“I am opposed to putting affiliate restrictions in any charter. They’re not in any other charter,” Buffington said. “What I fear is you put the restriction in one charter, then everyone is going to come here and ask for similar language.”
Monroe suggested it would be worth the governance committee’s time to discuss affiliate restrictions and the number of working group members.
“It’s not the number of people, it’s the chair getting organized and ensuring people express their opinions,” he said.
The MOPC also approved modifications to the Model Development Working Group’s (MDWG) charter. The stakeholder group said the changes reflect current practices and adds references to assignments from the TWG, MOPC and Board of Directors and the development of models for reliability standard TPL-007-1 (Transmission System Planned Performance During Geomagnetic Disturbances).
The MDWG reports to the TWG and is responsible for the coordination, development and maintenance of SPP’s transmission system planning models.
OG&E Raises Concerns over Third-party Tx Line Upgrade
Members voted to table a sponsored upgrade of an OG&E transmission line in northern Oklahoma, accepting the utility’s request to give it more time to work out legal issues.
The work would be sponsored by EDF Renewable Energy, which wants to upgrade terminal equipment and rebuild an 11-mile, 138-kV line near Ponca City and its 154-MW Rock Falls wind farm, which became operational in December. EDF has said it will seek cost recovery through SPP’s Attachment Z2 revenue crediting or incremental long-term congestion rights.
EDF presented the project to the TWG under SPP’s new transmission planning process. The TWG approved the project in March after determining there wasn’t a reliability impact. SPP Vice President of Engineering Lanny Nickell told members he was unsure whether the upgrade has ever been studied as an economic project in previous RTO planning studies.
OG&E pushed back against the project, saying it has engaged outside legal counsel to understand the consequences of having a third party pay to rebuild a line. McAuley noted his company is already recovering costs on the line through an annual transmission revenue requirement, but it is unclear what will happen to its depreciation or how to expense additional maintenance costs following the rebuild.
“At first blush, someone comes in and says they want to rebuild a line, you say, ‘Fine. What’s the big deal?’ That’s probably what the TWG said,” McAuley said. “We have an existing line with an ATRR that’s recovering revenue. What happens to that? This has opened up a broader set of legal questions we don’t have answers to yet.”
EDF did not have a representative in the room to participate in the lengthy discussion, but the company’s transmission strategy director, Omar Martino, was eventually patched in to answer questions. He said EDF understood the region is facing congestion issues, but that no one had committed to the upgrade.
“To the extent we can alleviate congestion and protect ourselves from congestion pricing, the upgrade would provide sufficient relief for the wind farm,” Martino said. EDF hopes to see the upgrade in place by June 2019.
“Bottom line, we have a whole lot of questions and not many answers,” McAuley said, suggesting a revision request be drafted if SPP’s Tariff doesn’t supply enough guidance. “I think it is precedent setting, and we might want to take a little bit longer look at it.”
SPP determined that while the vote was to determine MOPC’s endorsement, RTO staff still have the responsibility to bring the proposal to the Board of Directors for its approval. In the meantime, OG&E’s counsel will meet with SPP’s legal staff to resolve its questions.
Six members voted against tabling the proposal and two abstained.
Members did endorse a second sponsored upgrade, the addition by City Utilities of Springfield of a second 161/69-kV transformer at its James River Power Station. The upgrade has a June in-service date.
Members Approve Three-Stage Process for GI Requests
Members easily approved a task force’s white paper that overhauls SPP’s process for handling generator interconnection requests. BP Wind Energy North America abstained from the vote.
The Generator Interconnection Improvement Task Force’s (GIITF) paper outlines a three-stage process comprising a thermal and voltage analysis, dynamic stability and short-circuit analysis, and a facilities study.
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An increasing security deposit is required before each step, beginning at $2,000/MW and escalating to 10% and 20% of allocated upgrade costs, respectively. A decision period follows each stage, allowing transmission customers to determine whether to proceed to the next step following receipt of study reports.
The GIITF’s work replaces the current convoluted process, which involves feasibility, interconnection and system impact, and facilities studies, bidirectional work flows, and mandatory and optional steps.
Tamimi, the task force’s chair, said the simplified process will be easier for SPP to administer and for customers to understand and navigate. He said most upgrades will be identified in the first stage, allowing customers to make informed decisions before committing to a lengthy and expensive stability analysis.
Tying financial security to upgrade cost allocation will encourage customers to weigh the risks of proceeding at an earlier stage, reducing the number of requests that are withdrawn late in the process, Tamimi said.
The task force was created early last year to address SPP’s overloaded interconnection queue and requirements that could emerge from a rulemaking FERC opened in December 2016 to consider changes to its pro forma large generator interconnection procedures (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)
The commission has not approved any changes in the rulemaking. Earlier this month, however, FERC staff conducted a two-day technical conference to examine how SPP, PJM and MISO coordinate interconnection studies on projects near their seams, after the commission said their practices may not be just and reasonable. (See Developers, Tx Providers Seek Direction on ‘Affected Systems’.)
The MOPC in 2017 granted the task force a one-year extension to develop a replacement for SPP’s current interconnection process.
Ciesiel Delivers Final SPP RE Report
Members gave Regional Entity President Ron Ciesiel a round of applause following what may have been his last update to the MOPC.
SPP’s RE has been dissolved and is in the process of transitioning its data and responsibilities to the Midwest Reliability Organization and SERC Reliability, where its 122 registered entities have been reassigned. (See NERC Board Approves Dissolving SPP Regional Entity.)
Ciesiel said he hopes to complete the work by July. He said 10 of the 17 remaining RE employees have found jobs within the RTO or elsewhere, noting cybersecurity personnel are “in great demand.” Two others have decided to retire.
McAuley complimented Ciesiel and his staff on their work, saying, “While we didn’t always agree with the audits, they were done well.”
Tx Planning Improvement Task Force Delivers Final Work
The Transmission Planning Improvement Task Force wrapped up three years of work by winning the MOPC’s unanimous endorsement of its 20-Year Assessment Manual, which now goes to the board for its final approval.
The assessment is intended to develop an extra high voltage (300 kV and above) transmission road map for the SPP region, with candidate projects helping inform shorter-term planning assessments. According to the manual, “The assessment will result in the identification of projects that economically deliver energy within the SPP region while addressing a reasonable range of future industry uncertainty.”
The manual lays out roles and responsibilities within the 20-year assessment, study process and data inputs. The manual has been approved by the task force, the TWG and the Economic Studies Working Group.
Unanimous Consent Agenda Includes 9 RRs
Members unanimously approved the consent agenda, which included the re-baselining of a Nebraska Public Power District 69- and 161-kV project, from $37.8 million to $27.5 million; removing OG&E remedial action schemes at the Centennial and Crossroads wind farms; and nine revision requests:
GIITF RR267: Eliminates the “standalone scenario,” which considers each interconnection request by itself, from the definitive interconnection system impact study process. This will free SPP resources to focus on the binding cluster study results, permitting results to be available earlier than they currently are. Staff will provide the standalone equivalent study models through existing confidentiality provisions to customers seeking to conduct a stand-alone scenario of their own.
MWG RR252: Assigns an out-of-merit energy (OOME) cap and/or floor, allowing staff to economically dispatch the resource down or up within the ranges.
MWG RR259: Modifies the market settlement posting and dispute timelines being implemented with the new settlement system, reducing the number of resettlement postings and manual processes resulting from revisions to meter and bilateral settlement schedules.
MWG RR273: Automates several the market settlement system’s charge types that are not yet part of revenue neutrality uplift processing, resulting in rounding/residual amounts that must be manually processed and distributed through miscellaneous charges. The new system is scheduled to go live in May 2019.
MWG RR280: Clarifies the settlement system’s reserve sharing group (RSG) processing by modifying the RtImpExp5minQty field with an attribute indicating whether the import/export quantity was because of an RSG event.
ORWG RR268: Clarifies or removes outdated language from the operating criteria, improving SPP’s ability to perform reliability coordinator, balancing authority, transmission service provider and reserve sharing group functions.
ORWG RR269: Clarifies language and removes antiquated and redundant language in SPP’s operating criteria and describes the existence of multiple standalone documents.
ORWG RR270: Converts the operating criteria Appendix OP-2 to a standalone document, clarifies language and adds formatting improvements.
PCWG RR255: Revises business practice 7060 by adding triggers to stop the annual escalation of undefined baseline costs when a designated TO provides 1) SPP a letter of commercial operation, 2) notification that an upgrade is in-service, and 3) notification that an upgrade is complete.
KANSAS CITY, Mo. — SPP’s Markets and Operations Policy Committee last week failed to endorse a revision request that would have required non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.
The Market Working Group’s (MWG) recommended revision request (RR272) will likely be appealed to the Board of Directors for its April 24 meeting.
A roll-call vote resulted in 62.3% of members favoring the measure, short of the necessary two-thirds majority. Transmission-owning members Western Farmers Electric Cooperative and Westar Energy, last in alphabetical order, cast the final two votes opposing the change to seal its fate, at least temporarily.
“I’m not saying I’m going to submit one, but I have a feeling there will be [an appeal],” said American Electric Power’s Richard Ross, who chairs the MWG.
NDVERs converting to DVERs would need to ensure they have the proper communication systems in place and the technical capabilities to reduce their output.
Ross said the Tariff change will increase market efficiency through the reduction of manual out-of-merit energy orders to mitigate constraints. The addition of dispatchable resources will only increase reliability, he said.
“Any time you’re taking actions out of market, you are creating inefficiencies,” said SPP’s David Kelley.
The Market Monitoring Unit expressed strong support for the Tariff change, saying it would help reverse the recent growth of negative real-time pricing. The Monitor’s recent quarterly report noted the frequency of intervals experiencing negative prices increased from 2.6% in 2015 to 7% through November 2017. (See SPP Market Monitor: Negative Prices May Require Rule Changes.)
“Negative pricing is a significant issue in our market,” MMU Executive Director Keith Collins reminded members. “Something that increases flexibility is at a premium, which we will highlight in our next report. Having non-dispatchable resources becoming dispatchable is an important piece of that recommendation.”
Collins said an SPP operations study revealed that “the more flexibility you have, you end up increasing [energy market] pricing” by reducing the magnitude of negative prices.
“All resources will benefit from that change, which will allow the integration of more and more variable resources in the system,” he said.
But Westar said the change would hurt SPP’s “market reputation.”
“NDVERs were a condition of several [market participants] agreeing to transition from [the Energy Imbalance Service to the Integrated Marketplace],” the company said in written comments. “If we go back on our word, will other [market participants] lose confidence in the stability of SPP tariff grandfathering and agreements made to prospective balancing authorities, asset owners and market participants considering the benefits of [joining] SPP as a stable settlement and market platform?”
Members accepted a friendly amendment to the revision, extending the registration deadline to January 2021.
The revision request exempts about 2,000 MW of resources without direct interconnection agreements with SPP or registered as qualifying facilities under the Public Utility Regulatory Policies Act. That drew concerns from members over whether Mountain West Transmission Group entities would be able to acquire similar exceptions.
“If the current language excludes those, it does appear to leave questions about those who joined SPP with a previous interconnection agreement, but not one with SPP,” said The Wind Coalition’s Steve Gaw. “Will they have to comply with this [requirement], or does the language exempt them, including the generators in the Mountain West region?”
“That’s exactly right,” said Oklahoma Gas & Electric’s David Kays. “When you’re being prospective about anyone coming in afterwards … I think it creates a hole in the Tariff, and I’m not sure that’s something we should be doing intentionally.”
Ross said there is no specific provision to carve out the Mountain West entities. “They’ll have to be prepared to comply with these requirements when they’re integrated into the SPP system,” he said. The MWG fashioned the change so that “anyone who wants an exception can make a [Federal Power Act Section] 200-whatever filing from that [requirement] at FERC,” he added.
Kelley pointed out that ISO-NE and CAISO have gone through similar conversions. He said the revision would help a grid that has “grown exponentially in size” with new wind resources and continues to hit new wind-penetration peaks.
“I go back to the overall problems we’re trying to address, which is overall market efficiency and reliability,” Kelley said. “When you hit those [constrained] situations, it’s imperative that the operators and markets have the tools to make the most efficient decisions on a systematic basis, rather than take out-of-market actions.”
The vote followed one of several vigorous discussions that livened up what staff and members had expected to be a perfunctory MOPC meeting.
“If you’re not careful, you’ll have an MWG meeting break out,” Ross joked.
FOLSOM, Calif. — At its first public meeting with potential customers of its reliability coordinator (RC) services Thursday, CAISO divulged that most of the load in the West has signed letters of intent for the new program.
In response to a question, CAISO Regional Integration Director Phil Pettingill said he could not say publicly who has signed letters of intent and nondisclosure agreements to receive RC services.
“What I feel like I can say is, most of the load that is in the Western Interconnection has signed those agreements with us,” Pettingill said. “We are really talking to almost everybody.”
He added that the letters of intent are not binding and can be withdrawn. The notifications that have been sent to Peak Reliability from customers planning to depart its RC program are also nonbinding.
NERC’s reliability standards require balancing authorities and transmission operators to procure RC services, which include outage coordination, real-time situation awareness, and system restoration coordination and training.
CAISO on April 5 issued its initial proposal for RC services, which it hopes to have running by May 2019. The ISO and Peak are also developing competing proposals for new energy markets that could develop into a full RTO. (See Multiple Entities, Markets Now Beckon in West.)
CAISO is now developing prices for its supplemental, non-core RC services, such as hosting advanced applications and addressing certain critical infrastructure protection services, Pettingill said in a presentation.
The ISO says its RC services will be much cheaper than Peak’s, but Peak countered that the comparison is not straightforward because Peak has more RC experience and offers certain customer services such as the WECC Interchange Tool, the Enhanced Curtailment Calculator and the Peak Synchrophasor Project. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)
In developing the RC services, the ISO will issue straw proposals and gather feedback to revise the initiatives. The final proposal will be subject to approval by the Board of Governors and FERC.
CAISO hopes for the commission’s approval in October.
The goal is for potential RC customers to export their network models by August and begin data integration and system verification in January 2019. RC service agreements would be executed in November with much of the integration and testing occurring next year, Pettingill said.
CAISO will use its “activity-based costing system,” which has been used for all rate design initiatives since 2011, to determine the costs of RC services.
About 6% of CAISO’s annual costs would be allocated to RC services in the revenue requirement for 2019 and 2020 rates, CAISO CFO and Treasurer Ryan Seghesio said Thursday.
“The ISO is committed to a really level, stable revenue requirement,” Seghesio said. CAISO’s revenue requirement of $190 million to $200 million has been stable for about 11 years. There is a FERC-approved $202 million cap on the revenue requirement, he said, to prevent surprises for market participants.
