LITTLE ROCK, Ark. — SPP began the public portion of integrating the Mountain West Transmission Group with a pair of lively stakeholder meetings Friday and Monday.
Representatives from the two entities shared details of SPP’s integration process, proposed modifications to the RTO’s governing documents and the integration’s timeline. The two meetings attracted about 325 current and potential SPP members, state regulators, and environmental and customer advocates in person or on the phone.
“This will start the debate process as we work together in a way that benefits both SPP and Mountain West,” SPP COO Carl Monroe said in kicking off the meeting at Mountain West member Tri-State Generation and Transmission’s offices in Westminster, Colo.
During a Monday meeting in Little Rock, SPP members peppered representatives with numerous questions about several of Mountain West’s proposals to modify the RTO’s stakeholder process.
The “Westsiders” have suggested:
Creating a Westside Transmission Owners Committee with decision-making authority over issues reserved to the transmission owners;
Prohibiting the SPP Board of Directors from changing decisions by the new committee, and replacing the board’s secret ballots with open ballots;
Expanding the Regional State Committee’s authority to include resource adequacy and congestion rights allocation oversight for SPP’s Western Interconnection region, and giving Western members of the committee the right to direct the RTO to make FERC filings; and
Adding seats on the board committees for Western representatives.
Kenna Hagan, senior manager of planning, policy and strategy for Black Hills Corp., said Mountain West’s proposals result from years of discussion among the coalition’s 10 utilities.
“This is a compromise position that’s taken us three years to derive,” Hagan said. “There’s strong interplay between each of those items we’re proposing. It’s not all or nothing … but it’s important to us to move forward as a group.”
Duke-American Transmission Co.’s Bob Burner called Mountain West’s suggestions “protectionist proposals,” saying, “It certainly discourages independent transmission developers from looking at anything on the west side.”
Other stakeholders questioned the differences between east and west in transmission cost allocations and rate design, but those involved in the negotiations worked hard to allay concerns.
“These are not meant to be two separate processes,” said Tri-State’s Mary Ann Zehr. “They’re supposed to work in concert with each other.”
“You’re bringing up things we will have to address [in the stakeholder process] and work through,” said SPP Associated General Counsel Mike Riley.
SPP and Mountain West are in the third stage of the RTO’s process for integrating new members, when staff will convene special all-member and stakeholder meetings to discuss proposed document changes. Mountain West triggered the stage when it said in September it had completed initial discussions with the RTO’s management team and would begin public negotiations. (See Mountain West to Step up Talks with SPP on Joining RTO.) Mountain West, which primarily services Colorado, Wyoming and Nebraska, announced its intentions in January to join SPP. The two entities are working on an Oct. 1, 2019, target date for membership.
SPP’s existing members will see a phased-in, reduced administrative fee. The fee, currently 48 cents/MWh, will drop to 43 cents for 2020, resulting in annual savings to existing members of $16 million to $25 million for the first three years and a total net present value benefit of approximately $209 million for the first 10 years of Mountain West membership, SPP said.
A Brattle Group study conducted for Mountain West found the entity could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with one. A separate Glarus Group study of DC tie flows in a combined Mountain West-SPP market showed “significant” benefits, with annual net production cost savings ranging from $11.7 million to $28.8 million.
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Any changes to SPP’s governing documents will be reviewed by stakeholders on the Corporate Governance Committee (governing documents), Strategic Planning Committee (negotiating strategies, new member deliberations), Markets and Operations Policy Committee (Tariff revisions) and the RSC (state regulatory agency input).
SPP’s board will have the final call on any changes.
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SPP will conduct a reliability assessment of each incoming member’s transmission system to ensure they meet the minimum reliability planning criteria. Staff performed similar assessments when it added Nebraska’s utilities and the Integrated System.
“We’ve been through this before,” said Lanny Nickell, SPP vice president of engineering.
VALLEY FORGE, Pa. — PJM’s plan for addressing uplift remains on schedule, and the final two phases of its three-phase solution will be filed by the end of this week, staff announced at Wednesday’s Market Implementation Committee meeting.
The two remaining phases will be filed separately. In May, after four years of debate, stakeholders endorsed the final phase of the plan despite opposition from financial marketers. The filings address allocation of uplift and limit the locations where financial traders can place bids. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
Bruce Bleiweis of DC Energy asked if PJM had any indication whether newly installed FERC Commissioner Robert Powelson would recuse himself from the decision. Powelson previously chaired Pennsylvania’s Public Utility Commission. PJM staff said they had no information on that.
Debate Continues on Intraday Offers
The results were mixed for the Independent Market Monitor’s proposed revisions to the intraday-offer procedures, which go into effect on Nov. 1.
Stakeholders endorsed a joint proposal from PJM and the Monitor on changes to Manual 11 that would allow reapplication of the three-pivotal-supplier test after offers are updated. However, they declined the Monitor’s recommendations on other Manual 11 changes to verification of energy offers and endorsed PJM’s plan. (See “PJM, IMM Agreement on Intra-Day Offers Seen as ‘Massive Change,’” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
The Monitor’s Catherine Tyler argued that PJM’s proposed energy-offer screen, which is being implemented to comply with FERC Order 831, fails to incorporate information from fuel-cost policies and other cost inputs. The offer-verification changes for demand response also don’t follow the rules already in place for generators, she said.
“I think there’s a real concern that if there aren’t more details in the manual, if there’s no [offer] cap, then an astronomically high offer could go through, and PJM has no process to stop payment without going to FERC.”
The Monitor, she said, is concerned that the process is not standardized. However, stakeholders hesitated to apply a standard before seeing how the process works in the real world.
“I think we have a learning curve, and while I don’t disagree with the value of a standard, I would suggest that having a standard without any history isn’t productive,” CPower’s Bruce Campbell said.
PJM’s proposal on verifying offers passed with one vote in opposition and 21 abstentions.
Give Them Some Credit
PJM is proposing to use modeling to improve its financial transmission right credit requirements. By incorporating the RTO’s PROMOD planning simulations, credit requirements can take into consideration the impacts of future transmission upgrades, PJM’s Hal Loomis said. Because system upgrades reduce congestion, they also decrease the value of nearby prevailing-flow FTRs.
The plan would analyze the impact of upgrades on FTR bid and cleared credit requirements. PJM’s threshold for analysis would be upgrades with at least a 10% impact on constraints with at least $5 million in congestion. Just three of the 22 system upgrades placed in service for 2017/18 fit those criteria.
PJM is proposing two implementation alternatives. The first, which staff prefer, would incorporate the PROMOD simulation results into the publicly available FTR credit calculator prior to the FTR bid window. While the RTO would only publish the difference between the simulation and historical values for each node, Loomis noted that some stakeholders have complained it would provide market intelligence.
“We know transparency is important to our members. It’s also important to FERC,” Loomis said.
The second option, which resembles the current undiversified adder process, would have PJM issue incremental collateral calls between the close of each FTR bid window and publication of the cleared auction results. While this doesn’t give away information, it could require posting additional collateral within a day. Those who miss the deadline would have their bids removed.
PJM hopes to implement one of the processes in time for the 2018/19 annual FTR auction next spring and apply it to all existing positions. Members with a credit shortfall will be restricted in their FTR transactions during a 12-month “transitional cure period” in which they won’t be at risk of default but can only make transactions that reduce their credit exposure. No collateral returns will be allowed until the shortfall is cured.
“If there’s a shortfall, we want members to cover the shortfall,” Loomis said.
A poll in PJM’s Credit Subcommittee found strong support for all facets of the proposal, including the RTO’s preference for posting the nodal differences, Loomis said.
DC Energy’s Bleiweis suggested better alternatives are available, adding that “PJM should keep its views of the future confidential.”
Instead, he said, the PROMOD data should be supplemented with third-party forecasts.
“One of the issues we had with the poll is we weren’t able to answer the questions we wanted to answer,” he said. “There are experts out there who do congestion forecasting. PJM should work with them.”
He made the argument during a presentation on his company’s concern that the rule changes would still allow participants to hold substantial FTR portfolios while posting little or no collateral. DC recommends a minimum collateral threshold, along with scaling capitalization requirements for increasingly risky positions. Bleiweis also recommended a mark-to-market test in which PJM would collect additional collateral based on the current market value of the purchaser’s FTR portfolio.
He acknowledged that these recommendations would “absolutely” increase DC Energy’s credit requirements.
“We think it’s critical to protect the market,” he said. “The worst thing that can happen to the FTR market is another default. We had one in 2008.”
PJM Chief Financial Officer Suzanne Daugherty asked stakeholders to address the issue sequentially rather than with an omnibus solution. “We’d like to get this one known exposure addressed,” she said.
Bleiweis acknowledged PJM’s progress on the issue and agreed to take his proposal to the subcommittee in exchange for Daugherty’s commitment that it would be addressed soon.
“Over the last 13 years, we’ve made a lot of progress on credit issues. We’re not going to stand in the way,” Bleiweis said.
Earlier in the meeting, stakeholders also endorsed proposed changes to credit requirements for regulation resources to allow credits to offset charges daily. The existing process settles credits monthly but charges weekly, which can create a collateral requirement within the month despite the existence of a much-larger outstanding credit. Travis Stewart of Gabel Associates, which identified the issue and advocated for the change, thanked PJM for the effort.
Stakeholders were uncharacteristically divided on whether to allow discussion of concerns raised by the Monitor on the long-term FTR market but eventually assented to it. Monitor Joe Bowring presented a problem statement and issue charge on FTRs with terms of one or three years, which he said have a very concentrated ownership and don’t accurately reflect the prices in corresponding annual FTR auctions. He suggested there was a lack of interest in the product.
“It has become increasingly clear that the three-year FTR product sold in the long-term FTR auction should be eliminated,” the Monitor said in its State of the Market report for the first half of 2017.
Bowring and Vitol’s Joe Wadsworth sparred over the Monitor’s goals and perception of the problem. Wadsworth asked if Bowring’s interests were in improving the efficiency and liquidity of long-term market transactions or simply abolishing FTRs. Bowring responded that the question is whether long-term FTRs are helping or hurting the efficiency of markets overall.
“That’s not a very clear answer to me. Take that as constructive [criticism]. Take it as nothing more than that,” Wadsworth said.
Rather than a lack of interest, there are impediments, like regulatory uncertainty, that make many participants nervous about transacting years in the future on energy products in general, he said. He later added that Vitol supports open dialogue and wouldn’t vote against having a discussion.
Marji Philips of Direct Energy said it was interesting that Bowring’s proposal was “being picked apart … which tells me that everyone picking it apart is afraid of losing money.”
“We don’t see any harm” in the discussion, she said.
The measure received 64% approval with a vote of 108-60 and 53 abstentions.
OPSI, PJM at Odds over PRD
State regulators are at odds with PJM over requirements for demand-side resources, including price-responsive demand (PRD) bids.
PJM says PRD bids should be available year-round, the same as generation resources under Capacity Performance rules. But the Organization of PJM States Inc. (OPSI), which speaks for the state regulators, argues they should be allowed to make seasonal contributions.
The dispute came to a head during PJM’s presentation of its proposed PRD rule changes to match CP requirements. PJM’s Pete Langbein outlined three proposals. The RTO’s proposal would extend annual requirements developed for DR to PRD. A second proposal would limit the triggers for assessing CP penalties to just penalty assessment intervals. The third, from DR-participant Whisker Labs, would extend the existing PRD rules to the winter, create a summer-only product and allow it to be aggregated with a winter resource for an annual CP resource.
OPSI Executive Director Greg Carmean made a statement developed from a resolution OPSI sent to PJM’s Board of Managers on Oct. 9 urging the grid operator to create market mechanisms that enable participation of summer-available demand resources.
Bowring said that if PRD bids are meant to be price responsive, they should be energy resources rather than capacity.
The issue has existed since PJM implemented its CP construct in response to the 2014 polar vortex. CP requires that all resources have year-round availability and includes penalties for those that fail to respond during emergencies.
OBF Changes
PJM’s Tim Horger announced that PJM has alertedNYISO that it plans to end the controversial 400-MW operational base flow (OBF) through northern New Jersey on Oct. 31, 2019.
The OBF was created in May in response to Consolidated Edison ending its decades-old agreement with Public Service Electric and Gas to “wheel” 1,000 MW from upstate New York through PSE&G’s northern New Jersey territory and into New York City. Amid stakeholder complaints about its necessity, PJM decided to retain 400 MW of that flow as the OBF.
PJM now says it won’t need the cushion to manage energy flows in the area once the Bergen-Linden Corridor project is complete. Per the grid operators’ joint operating agreement, PJM provided NYISO two years’ notice of the change, which NYISO acknowledged.
OVEC Joining
The Ohio Valley Electric Corp. (OVEC) is planning to join PJM. OVEC’s Scott Cunningham said the company plans to join PJM as its own transmission zone, despite having no load to service.
OVEC, which is headquartered in Piketon, Ohio, owns 2,200 MW of generation capacity but will have no load after a U.S. Department of Energy contract ends sometime before 2023. The company was created in 1952 to service roughly 2,000 MW of load from a uranium enrichment plant near Piketon operated by the Atomic Energy Commission.
DOE, which took over operation of the plant after the commission was abolished in 1974, ceased operations there in 2001. The department ended the 2,000-MW contract in 2003 but maintains a load that can be 45 MW at its maximum but is generally less than 30 MW. In months with mild weather, it is less than 20 MW, Cunningham said.
OVEC’s two coal-fired generating plants are already pseudo-tied into PJM, and its eight “sponsors” are allowed to sell their portions of the output into PJM’s markets. OVEC has no distribution and does not belong to an RTO, although its reliability coordinator function is performed under an agreement with MISO.
The generation would become internal to PJM following membership, eliminating the pseudo-ties, American Electric Power’s David Canter said. AEP is one of OVEC’s sponsors.
PJM’s Asanga Perera said there might be some auction revenue rights associated with the membership.
VALLEY FORGE, Pa. — Stakeholders approved PJM’s 2017 installed reserve margin (IRM) calculations at last week’s Planning Committee meeting.
The updated calculations reduced the IRM from 16.6% to 15.8% for delivery year 2021/22, thanks to an anticipated fleet-wide equivalent forced outage rate (EFORd) reduction from 6.59% to 5.89%. PJM calculated EFORd — which measures the probability a generator will fail completely or in part when needed — for the existing generation fleet and the fleet expected in future study years. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)
PJM also reduced the winter weekly reserve target for each month this winter. December dropped from 24% last year to 23% this year. January’s target fell from 30% to 27% and February from 28% to 25%.
PJM is planning to revise its evaluation process for new and upgrade transmission service requests to provide early analysis of recommended upgrades and cost estimates. The initial study, which does not address the upgrades or cost estimates, would be replaced with a feasibility study, PJM’s Ed Franks said. The subsequent system impact and facilities studies would remain the same. (See “Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues,” PJM Planning and Tx Expansion Advisory Committees Briefs.)
“The analysis as it’s currently done is just constantly refined as projects drop out of the queue. That’s just the nature of the process,” Franks said. “We feel that at least giving them something up front high-level is more appropriate than having them wait until the impact study to get something.”
Franks said PJM could evaluate and consider combining the feasibility and impact studies if customers preferred that approach. The changes don’t apply to requests that enter the queue through available transfer capability calculations.
PJM is planning to request FERC approve an April 1, 2018, implementation, which will require the Markets and Reliability Committee endorse the Tariff changes in December and the changes to Manual 14A in February. Necessary changes for Manual 2 will be developed through the manual’s usual endorsement process.
PJM is hoping to continue developing its transmission design standards with new underground line construction guidelines, but transmission customers question their usefulness. (See “Competitive Planning Components Endorsed; Pieces Remain,” PJM Planning & Tx Expansion Advisory Committees Briefs.)
Transmission developers acknowledge the standards when they sign PJM’s designated entity agreement (DEA) to receive approval to construct a project, but the RTO does not enforce them. DEAs are required for companies assigned projects through PJM’s competitive-bidding process. Customers were concerned that the standards don’t bind the developers to any specific actions.
“It raises the question for me … is whether all underground construction should be held to the same … standard,” said Ed Tatum of American Municipal Power.
“PJM is not going to go through a checklist with the proposing entities ensuring that they considered all of … the minimum standards. It’s more for an awareness,” the RTO’s Michael Herman explained. Some of the highly detailed standards are “really beyond the scope of tracking,” he said.
“These are minimum standards,” PJM’s Sue Glatz added. “These are not the only standards that apply to transmission projects.” Transmission owners have their own, she said.
As PJM works on factoring resilience into planning, stakeholders are hoping the new criteria will address specific issues. PJM’s Mark Sims provided an update on the RTO’s progress, which elicited questions from state advocates.
Ruth Ann Price with the Delaware Division of the Public Advocate asked about a comment PJM CEO Andy Ott made at the Grid 20/20 conference in September. Ott had said that one of PJM’s resilience goals would be to make “critical facilities less critical.” (See PJM Defends Resilience Focus as Pre-emptive, not Excessive.)
Price asked how that concept would be applied in PJM’s planning, but the RTO’s Steve Herling cautioned against jumping to conclusions.
“That’s just an example that Andy was using as to how we might visualize the problem and how we might go about solving them,” he said.
Greg Poulos, executive director the Consumer Advocates of the PJM States, was disappointed PJM isn’t specifically focused on that goal.
“I was really surprised to hear that’s not a main emphasis. I didn’t realize it was just an example and not a major project,” he said.
PJM staff asked for patience in developing a plan.
“Traditional power flows are well understood. They haven’t changed much over time, those metrics. But for resilience, we’re creating brand new metrics,” Sims explained. “I think the approach is to set a longer timeline … but we’re still very much working on the technical side of things.”
Interconnection Webpage Gets a Facelift
PJM has redesigned its webpage for the interconnection queue to incorporate more information. PJM’s Tawnya Luna unveiled the new look, explaining that it includes new county-level and megawatt filters. Users will be able to save a list of projects and receive weekly or monthly updates on them via email.
The site will change over in late October. PJM is seeking feedback for future revisions, Luna said.
How Immediate is Immediate?
Transmission customers and merchant transmission developers joined together at last week’s meeting of the Transmission Expansion Advisory Committee to raise concerns about PJM’s categorization of “immediate need” projects.
The debate began when Sims described modifications that will raise the costs of a project in Dominion Energy’s territory. The b2361 project northeast of Fairfax City, Va., originally ran about 4.5 miles from the Idylwood substation to a new Scott’s Run substation and was expected to cost about $32 million. But that plan ran into siting issues at Scott’s Run. The project’s scope has been expanded to instead rebuild the Tysons substation and run the line there for a total cost of at least $111.7 million. The project’s in-service date has also been moved back five years to 2022.
Mark Ringhausen with Old Dominion Electric Cooperative said the changes should warrant including the project in PJM’s competitive bidding processes for transmission projects that were developed through FERC Order 1000, but Dominion’s Ronnie Bailey disagreed.
“I don’t think an Order 1000 process would get us to a better answer,” he said.
Sims said the project has already been approved for construction by PJM’s Board of Managers.
“We’re changing to scope for it,” he said.
“This seems a little different than a routine scope change because it’s a five-year scope change,” said LS Power’s Sharon Segner. “Delaying the in-service date by five years would clearly put this project not in ‘immediate need.’ … We would encourage this immediate-need designation process to not be a rubber stamp process.”
PJM’s Tariff requires that “immediate need” projects must be in service within three years. But Sims clarified that the designation refers to when the project is needed, not when it will be in service.
John Farber with the Delaware Public Service Commission brought up the issue again later in the meeting during a discussion of projects in Public Service Electric and Gas’ territory.
“Really, it’s a ‘wanted by’ date, and the ‘required date’ is when it actually goes into service?” he asked.
Sims said the “required in-service date” is when the project is needed, but that date can’t always be met. He added that it’s “a little circular” to suggest competitive bidding for such projects would be faster at defining an in-service date because that wouldn’t be known until the end of the bidding process.
PJM told the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) that it would eliminate the minimum offer price rule (MOPR) and include all units to which it currently applies in its new repricing structure.
“We would apply repricing as opposed to a MOPR approach,” said Stu Bresler, PJM’s senior vice president for operations and markets. He said existing MOPR exemptions would continue.
Bresler also announced two other changes to its proposal.
Any offers that trigger repricing would have their offer adjusted to the avoidable cost rate (ACR). PJM would maintain a table of default ACR values by resource class and location, but resource owners could submit unit-specific ACRs if preferred. “We heard loud and clear through the poll results that net CONE [cost of new entry] times B [as the adjusted offer] was not a popular approach,” Bresler said.
In addition, states’ option to direct PJM to pay adjusted resources less than restated capacity prices was removed. In the revised proposal, every cleared resource will receive the restated clearing price.
The number of proposals before the task force dropped by one when John Horstmann of Dayton Power and Light retracted his “capacity choice” proposal. That leaves eight options before the task force; Old Dominion Electric Cooperative had removed its repricing proposal from consideration in September.
There was no mention at the meeting of the Organization of PJM States Inc.’s Oct. 9 letter warning the PJM Board of Managers away from task proposals that OPSI said could raise prices significantly and restrict state public policies. (See related story, State Regulators Unhappy with PJM Capacity Discussions.)
But several proposers made revisions that appear to be keeping OPSI’s concerns in mind. American Municipal Power and LS Power updated their definitions for an “actionable” subsidy that expand upon the Independent Market Monitor’s definition for its extended MOPR proposal. The definitions identify exclusions for government-sponsored or -mandated procurement. The LS proposal specifically excludes renewables development and demand response programs.
The Monitor likewise added two exemptions to its MOPR proposal for public power and renewable portfolio standards.
CARMEL, Ind. — After months of stakeholder discord surrounding MISO’s plan to incorporate external zones into its capacity auction and divvy up excess auction revenues, Entergy last week emerged with its own plan.
The proposal comes a month after the RTO announced it would delay creation of external zones until the 2019/20 planning year and asked stakeholders to come forward with ideas on hedging mechanisms that would distribute excess revenues to external resources. (See MISO Postpones External Zones Until 2019 Auction.)
During an Oct. 11 Resource Adequacy Subcommittee meeting, Entergy’s Rachelle Johnson offered a proposal in which market participants would request hedges for supply arrangements with an external resource once a year. To be eligible, those arrangements must be active during the upcoming delivery period, have a term of at least five years and not already be covered by a hedge, Johnson said.
MISO would then perform a feasibility test of requested hedges using auction estimates from its loss-of-load studies, and deny hedges if they exceed estimated funds. If the amount of surplus auction revenue was insufficient to fund all outstanding hedges, then the funding of those hedges would be reduced proportionally.
Market participants would receive hedges for the next five years in the event the resource did not clear in the auction, Johnson said.
WEC Energy Group’s Chris Plante asked whether the proposal intended to align hedging with firm transmission service. Johnson said it could.
Indianapolis Power and Light’s Ted Leffler wondered whether external resources with firm transmission service would stop promising capacity to a particular zone, and instead shop for the best zonal resource credit.
“Are you just going to look for the easiest, cheapest place to dump it?” he asked, adding, “Not that that’s a bad thing.”
Laura Rauch, MISO manager of resource adequacy coordination, said firm deliverability means to deliver load to anywhere within the RTO, not to any particular zone or load.
Plante, who is also RASC chair, asked for more stakeholder proposals on how to provide hedges to external capacity suppliers. “This is why MISO delayed this, to get more stakeholder input on this topic,” he reminded stakeholders.
Rauch said MISO will continue to hold discussions on external zones in upcoming meetings up until its planned filing with FERC in early spring. She said MISO would lead more discussion on external zone hedging, in addition to how pseudo-tied resources and fixed resource adequacy plans would interact with external zones and how it will define border resources.
SAN DIEGO — The CAISO-run Western Energy Imbalance Market (EIM) has increased the operational flexibility of the region’s utilities and is leading to changes in resource procurement in states outside California, utility representatives said last week.
Speaking on a panel at Infocast’s Transmission Summit West, Matt Lecar, Pacific Gas and Electric principal of ISO relations and FERC policy, said “one of our big challenges is managing solar generation, and the EIM has been extremely valuable” by absorbing generation and reducing curtailment of renewables.
“We get to use more of our clean energy, more of the time,” Lecar said.
The EIM is also serving as a “proving ground as to how create a governing structure for a regional RTO,” he said, creating more planning certainty for entities in the West.
“The key here is to develop a culture of trust,” he said, adding that the EIM is proving the benefits of a regional market, and “the biggest enemy of trust is uncertainty.”
Even though the EIM is presently only a balancing market, it is already having an effect on resource planning in other states, NV Energy Director of Energy Market Policy Lauren Rosenblatt said.
“Now Nevada is highly affected by the regional resource mix in ways it wasn’t before,” she said. Nevada gets a lot of negatively priced solar energy from California, so power suppliers are less likely to build solar photovoltaic because they have the opportunity to obtain solar output from next door.
Idaho Power Vice President of Power Supply Tess Park said it is a positive that the EIM doesn’t require a participant to stay in the market for years, and if things don’t go well, “there is an out.”
The EIM has grown since its launch in November 2014, and panel participants said it has allowed energy resource-rich areas in the western interior to more effectively link up with the load-heavy population centers on the California coast. CAISO said the EIM produced $39.52 million in benefits for its participants in the second quarter, with CAISO gaining the largest share. (See CAISO Leads EIM Q2 Benefits, Exports.) As of the end of the second quarter of this year, benefits have been $213 million from more efficient dispatch, reduced renewable curtailment and reduced need for flexible ramping capacity, the ISO has said.
Portland General Electric joined the EIM on October 1 | CAISO
CAISO Strategic Alliance Director Don Fuller said the EIM has brought better economics and resources to electricity sector participants in the West. By taking advantage of excess capacity on the existing transmission system, the EIM helps avoid building of new transmission lines and makes for a more efficient regional grid.
“The idea was to take advantage of unused transmission, so it worked without new transmission,” Fuller said, adding that as new market participants bring transmission in, it helps all EIM entities move energy around.
The EIM took advantage of CAISO’s existing market platform and allowed easy entry and exit, allowing individual balancing authorities to retain control over their assets and join when they wanted. That has been a “key factor” in its growth, he said.
The market “has been another tool in our effort to manage renewables” and allows neighboring states to take advantage of low-cost power being produced in California, Fuller said.
Portland General Electric on Oct. 1 became the latest utility to begin operating in the EIM, and others have agreed to join but have not yet begun participating. Active participants include PacifiCorp, NVE, Puget Sound Energy and Arizona Public Service. Idaho Power and Powerex are due to join in 2018; Seattle City Light, the Los Angeles Department of Water and Power, and Balancing Authority of Northern California in 2019; and Salt River Project in 2020.
SAN DIEGO — The fate of the West’s coal-fired power was already sealed prior to EPA’s announcement that it will seek to repeal the Clean Power Plan, a panel of industry participants said last week at Infocast’s Transmission Summit West.
But those panelists also agreed there has not been adequate consideration of the impact of coal retirements on the region’s grid. The Trump administration argued that former President Barack Obama’s call for switching to more natural gas and renewable generation caused the agency to exceed its authority. (See EPA to Announce Clean Power Plan Repeal.)
ITC Grid Development’s Ron Belval said that while federal regulation affects coal-fired power, “I think it is going to be an economic decision; the wheels have already been set in motion” by low gas prices and more penetration of renewables. There might be some extension of the life of existing plants, but they will still be retired, he said.
The Western transmission network was designed for a traditional resource mix serving certain load centers, including areas that are served by coal, gas and nuclear, Belval said. The retirements of coal-fired plants will dramatically change how the system will be utilized, but the characteristics of the new system have not been identified.
Belval noted that there are also the requirements of California’s “duck curve” to consider. It is unclear what the mix of new resources will be or exactly where they will be deployed, he said, and the grid has needs in terms of frequency response and voltage regulation.
By 2025, about 5,000 MW of coal-fired capacity is scheduled for retirement in the West — basically all the large plants, according to Keegan Moyer, a principal with Energy Strategies.
“That is most of it; there is not that much more after that,” he said, adding that there is a not a “cookie-cutter” strategy for replacing those resources.
The retirements will free up transmission capacity that could be used by other resources, creating opportunities for new entrants, panelists said.
The transmission system is designed around natural gas plants that have also served to balance renewables and can quickly ramp up, and operators also are used to certain conditions, Belval said. “I suppose you could replace the gas resources, but I don’t know what those would be,” he said, noting that other resources are “not tried and true.”
“You have got to replace those with something that you know works,” and those resources need to be modeled in the operational time frame, he said.
Brian Cole, director of engineering at Arizona Public Service, said that at his utility, “the schedule for shutting down the older [coal] plants had already begun to be put in place. The Clean Power Plan just helped cement that and make that happen.” System operators are seeing the impact of renewables at the transmission and distribution levels, he said.
The coal-fired Mojave Generating Station in Nevada ran from 1971-2005
“We are trying to get our arms around it,” he said, adding that the removal of baseload generation also requires new ramping capabilities.
The CPP’s repeal effort has been accompanied by Energy Secretary Rick Perry’s recent directive that FERC ensure cost recovery for at-risk coal and nuclear generation in organized markets, representing an additional seismic shift in direction at the federal level. (See Perry Orders FERC Rescue of Nukes, Coal.) But panel participants indicated that the proposals are a long way from causing a surge in demand for coal-fired energy resources in Western states.
American Electric Power has filed a complaint against MISO for failing to collect and distribute millions in transmission charges from three defunct load-serving entities more than a decade ago.
In an Oct. 10 filing with FERC, AEP claimed that MISO owes more than $4.8 million to its PJM transmission affiliates after MISO failed to bill seams-related surcharges to energy providers Nicor Energy, Engage Energy America and The New Power Co., all of which shuttered before December 2004, when MISO created the charges (EL18-7). Nicor folded in 2003 amid financial fraud allegations, while New Power was liquidated in bankruptcy that same year. Engage went out of business in 2004.
AEP is seeking the money through the Seams Elimination Charge/Cost Adjustments/Assignments (SECA), a non-bypassable surcharge in MISO’s Tariff intended to recover lost revenues for a 16-month transition period during the elimination of through-and-out rates in late 2004 in the MISO and PJM regions.
AEP said that when MISO was setting up the SECA invoice system, Nicor, Engage and New Power were already defunct and not invoiced, but the RTO nevertheless listed their ensuing charges and “allocated even more SECA charges to the Nicor Energy and Engage sub-zones (based on 2003 data).”
“The allocation of SECA charges to nonexistent LSEs thwarted recovery of the SECA charges, ran counter to fundamental cost allocation principles and resulted in cost subsidies by reducing the SECA responsibility of others,” AEP said. “MISO did not bill and collect SECA charges from the three nonexistent LSEs, nor did it adjust the SECA charges allocated to them (as the RTO did to others) and, therefore, did not remit to the PJM [transmission owners] the revenue from all allocated SECA charges.”
AEP said it asked for compensation from MISO in conference calls in November 2016 and the following August, but the RTO refused to pay. The company asked FERC to either order MISO to pay the charges with interest or set up settlement proceedings to resolve the dispute.
WASHINGTON — A court ruling requiring FERC to consider the impact of greenhouse gas emissions won’t have a “significant” impact on the agency’s licensing of natural gas pipelines, Chairman Neil Chatterjee said Friday.
On Aug. 23, the D.C. Circuit Court of Appeals ruled 2-1 that FERC’s environmental impact statement (EIS) for the Southeast Market Pipelines Project should have included “reasonable forecasting” of the project’s impact on GHG emissions.
FERC had contended that the impact of the pipelines on GHG emissions was unknowable, dependent on variables including the operating decisions of individual plants and regional power demand.
Ruling in a challenge by the Sierra Club, the court said FERC had failed to meet the requirements of the National Environmental Policy Act. FERC “should have either given a quantitative estimate of the downstream greenhouse emissions that will result from burning the natural gas that the pipelines will transport or explained more specifically why it could not have done so,” the court ruled. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
In a press conference Friday, Chatterjee said he didn’t “believe that [the court’s ruling] was going to significantly alter the way that we evaluate these projects.”
Nexus Order
As an example, he pointed to the commission’s Aug. 25 order approving the Nexus Gas Transmission Project, a 255-mile pipeline from Ohio to Michigan (CP16-22) that is being built by DTE Energy and Enbridge’s Spectra Energy. The order contained a lengthy discussion of the environmental impacts of the project, arguing that its analysis complied with the National Environmental Policy Act.
The commission also noted that, in the final days of the Obama administration, EPA had requested the removal of a statement from the project’s EIS that said that there is no accepted methodology for correlating specific GHG amounts to changes in a region’s environment. The agency also asserted that comparing a project’s emissions to statewide emissions did not contribute to an analysis on global climate change.
“The EPA provides no compelling reason to change or supplement the final EIS,” FERC wrote. “The final EIS specifically notes that comparing project-related GHG emissions to statewide GHG inventories provides a frame of reference for understanding the magnitude of GHG emissions in general, but that it does not indicate significance. … The final EIS appropriately discusses climate change, quantifies project-related GHG emissions, identifies emission reduction and mitigation measures and programs, and notes the projects’ consistency with climate goals in the Midwest region.”
“In many ways, that approval anticipated the court’s argument in the Southeast case and addressed a lot of it,” Chatterjee said. He declined to comment on any other projects.
The Sierra Club requested rehearing in the Nexus case, saying the commission’s GHG evaluation failed to meet the D.C. Circuit’s requirement. “Regardless of what methodology FERC ultimately uses, it cannot ignore the issue by claiming, without support, that there is no way fulfill its duty committed to it by NEPA,” Benjamin A. Luckett, senior attorney for Appalachian Mountain Advocates, wrote on the Sierra Club’s behalf.
Southeast Markets’ Supplemental EIS
On Sept. 27, the commission responded to the court’s remand on the Southeast Markets project with a supplemental EIS that included estimated GHG emissions but maintained that the project would have no significant effect on the environment (CP15-16, et al.).
| Duke Energy
The 685-mile project by Duke Energy, NextEra Energy, Spectra Energy Partners and the Williams Companies, is composed of three interconnected pipelines in Alabama, Georgia and Florida: the Hillabee Expansion Project, Sabal Trail and the Florida Southeast Connection.
FERC’s supplemental EIS concluded that three Florida natural gas generators that would be supplied by the pipelines — Florida Power & Light’s new Okeechobee Clean Energy Center; Duke Energy’s new Citrus County combined cycle plant and FPL’s existing Martin County Power Plant — would emit as much as 12.5 million metric tons of CO2e annually while retirements of coal, oil and natural gas plants replaced by the new units would eliminate 6.14 million metric tons — a net increase of 6.36 million.
Burning of the pipeline’s uncommitted capacity could add an additional 2 million metric tons, FERC said. The net total of 8.36 million metric tons equals 3.7% of Florida’s GHG emissions in 2015, the commission said.
The commission said, however, that it was unable to find a method to “attribute discrete environmental effects” to the emissions. “The atmospheric modeling used by the Intergovernmental Panel on Climate Change, Environmental Protection Agency, National Aeronautics and Space Administration and others is not reasonable for project-level analysis,” the commission said.
FERC also said the social cost of carbon tool is not useful for project-level NEPA review because it does not measure the incremental impacts of a project on the environment. The commission also cited a lack of consensus on the appropriate discount rate and “the monetized values that are to be considered significant for NEPA reviews.”
| Duke Energy
A group of Albany, Ga., residents responded to FERC’s supplemental filing with a protest, saying “it assumes that coal-burning power plants will be shut down in the future but does not consider the methane output from the many compressor stations that are also planned for these pipelines.”
Other Approvals
On Friday, FERC issued certificates approving two other pipeline projects: the Atlantic Coast Pipeline (CP15-554, et al.), which will deliver up to 1.5 million Dth/d over 604 miles of new pipelines between Harrison County, W.Va., and eastern Virginia and North Carolina; and the Mountain Valley Pipeline (CP16-10, et al.), which will transport up to 2 million Dth/d from Wetzel County, W.Va., to Pittsylvania County, Va.
My last couple columns have explored the Department of Energy’s “Cash for Clunkers” proposal. The first column discussed how it will cost tens of billions of dollars and subsidize less reliable generating resources to suppress more reliable resources.[1] The second column showed that the proposal is the direct result of meetings between President Trump and Robert Murray, coal mine owner and major fundraiser for the president’s campaign,[2] not some deliberative process involving well-informed, well-intentioned people.
Robert Murray’s Confirmation
A shout-out to Murray for providing a smoking gun one day after my last column ran, confirming that the DOE proposal is all about selling more of his coal to FirstEnergy power plants, one way or another.[3]
1 in 5,000, and Then Some
Some folks may still think that the situation can’t possibly be that outrageous. The DOE proposal can’t be that devoid of merit.
Wrong.
The smoking gun below is from ReliabilityFirst, the regional reliability organization responsible for reliability in the Mid-Atlantic and Midwest states (the states that are the focus of the DOE proposal).[4]
| ReliabilityFirst
Please bear with me in explaining this graphic. It’s displaying the winter. The leftmost column is showing generating resources. The next column is showing possible reduction in those resources due to resource outages, based on the last five winters (including the polar vortex). The percentages on the left are the chance of cumulative outages exceeding the associated outage quantity.[5]
The biggest cumulative reduction in resources has a 0.2% chance of occurring. That is one in 500.
OK, now skip the 50/50 Demand column and look at the 90/10 Demand column. That reflects a one-in-10 chance of the coldest weather.
Please note that resources at a one-in-500 worst case (the second column) are still much more than the peak demand in the one-in-10 worst case (the last column).
In other words, combined there is much less than a one-in-5,000 (500 x 10) chance of peak demand exceeding resources in the winter.
And there’s more!
What if that less-than-one-in-5,000 situation were to occur? Fuel supply interruption is unlikely to be a major factor.[6] And RTOs like PJM have tools to avoid customer impact, such as public appeals for conservation and voltage reductions.[7] And any resource-demand shortage would last only hours, not weeks or of course months.[8]
The DOE proposal is much ado about nothing.
The Worm Will Turn
Here’s the third smoking gun. If FERC goes forward with subsidizing certain resources for an insignificant quality like fuel supply on site, it should recognize really important qualities like environmental/public health damage.[9] In the case of coal, the National Research Council of the National Academies estimates that coal generation causes pollution damage averaging $32/MWh.[10]
This means coal resources should pay $32/MWh for their generation, to be subtracted from whatever revenues they otherwise would receive. The payments should be distributed to those hurt by coal generation.
This administration won’t do that, but no administration is forever. Once the precedent is set for FERC to put its thumbs on the scales, coal better hope that the worm never turns.
Murray said he had pressed Trump and Energy Secretary Rick Perry to have the secretary order financial support for at-risk coal plants using DOE emergency authority, but department and White House lawyers ruled that out. “They didn’t want to declare the emergency,” he said. “It was a low point because we worked hard at it and knew it was needed.“They’re doing it in a different way,” Murray said. “Now we have another approach that’s in use to get to the same point.” https://www.eenews.net/energywire/2017/10/11/stories/1060063287↑
ReliabilityFirst says, “To the left side of the range of random outages are probability percentages related to the amount of random outages that equal or exceed the amount of outages shown above that line on the outage bar.” ↑
“Between 2012 and 2016, there were roughly 3.4 billion customer-hours impacted by major electricity disruptions. Of that, 2,382 hours, or 0.00007% of the total, was due to fuel supply problems.” http://rhg.com/notes/the-real-electricity-reliability-crisis. ↑
