FERC on Thursday approved Emera Maine’s proposal to provide discounted transmission service to two ReEnergy biomass plants in northern Maine (ER18-2123, ER18-2124).
The commission’s Sept. 27 order also found that a protest from Maine Gov. Paul LePage lay outside its jurisdiction. LePage alleged that Emera would recover the cost of the discounts from the state’s retail customers, but FERC said retail rates are regulated by the Maine Public Utilities Commission. “Our findings here are limited to whether Emera Maine’s proposed commission-jurisdictional wholesale rates are just and reasonable,” FERC said.
ReEnergy employee leads tour of Fort Fairfield biomass generator. | Biomass Power Association
ReEnergy owns a 39-MW biomass-fueled power plant in Ashland and a 37-MW biomass plant in Fort Fairfield. Both facilities have market-based rates and are allowed to sell their output into ISO-NE’s energy, capacity and ancillary services markets.
Under the agreements, Emera will provide non-firm transmission service from the two ReEnergy facilities to ISO-NE for $0/MW-month for Oct. 1, 2018, through Dec. 31, 2019, and $1,132/MW-month for Jan. 1, 2020, through Dec. 31, 2020.
ReEnergy said the discounts were needed to remain in business because of the pancaked transmission charges they pay to move energy to the ISO-NE market.
Emera would provide service to the plants through the Maine Public District transmission system, which is not directly interconnected with any portion of the U.S. transmission grid. Entities interconnected with it can only access the New England grid over transmission facilities in New Brunswick, Canada, which NB Power owns and operates.
Emera said it agreed to the discounts because ReEnergy provides jobs in northern Maine.
Texas regulators last week signaled their discomfort with the rising costs of CenterPoint Energy’s planned 345-kV transmission line to serve load in the industrial Freeport area south of Houston.
The Public Utility Commission has asked ERCOT to provide further input on CenterPoint’s project, which is part of the “Freeport Master Plan Project” addressing load growth around the Gulf Coast seaport.
“I’m not going to trust these huge shifts in costs without having ERCOT weigh in,” Chair DeAnn Walker said during the commission’s Sept. 27 open meeting.
CenterPoint’s application for a certificate of convenience and necessity presented 30 alternative routes, ranging in length from 54 to 84 miles, and in estimated costs from $481.7 million to $695.2 million. The costs at the lower end are almost double ERCOT’s estimate of $246.7 million when it approved the Freeport project in December. (See “Board Approves $246.7M Freeport Transmission Project,” ERCOT Board of Directors/Annual Meeting Briefs.)
“Some of these numbers are approaching those of a nuclear plant,” Commissioner Arthur D’Andrea said.
Warren Lasher, ERCOT’s senior director of system planning, didn’t argue that point. He explained that the grid operator made its recommendation based on “specific electrical reasons,” but it has taken a second look after CenterPoint notified it of the cost increase.
“From our very preliminary analysis, neither the need nor the timing for the need for the project has changed,” Lasher said. “When we looked at this project electrically, there were just not that many options to get to that part of the state and serve the increasing customer demand. I’m not sure we couldn’t have found another option, but it’s unlikely.”
ERCOT has projected a 92% increase in the Freeport area’s load to 1,979 MW by 2019, with a large chemical plant accounting for much of the growth. The region is expected to see an additional 300 MW of load by the end of 2022.
PUC staff agreed to prepare a preliminary order for the commission’s Oct. 12 open meeting. The order would incorporate ERCOT’s input on whether there are other alternatives for meeting the area’s demand.
“I am going to need that,” Walker said.
Rio Grande Electric, AEP Texas Reach Agreement
The commission canceled an Oct. 31 procedural hearing in the dispute between Rio Grande Electric Cooperative and AEP Texas over which utility will serve certain customers in a Uvalde subdivision after the companies said they had reached a settlement (Docket 47186). (See “Hearings Set for AEP Texas Legal Cases,” PUCT Reduces Rates for AEP, Others on Income Tax Cut.)
Rio Grande and AEP Texas told the commission they will resolve the dispute through requests for service area changes. They said they are finalizing maps and preparing the necessary documents to reflect “definitive boundary changes.”
The PUC gave the parties until Oct. 22 to file an agreement or a status update.
The commissioners accepted staff’s review of the state’s 14 investor-owned utilities’ earnings reports. Staff said none of the IOUs “warrant[ed] a more detailed analysis” (Project 48158).
Following a closed session, the PUC agreed to allow Walker, who represents the PUC on SPP’s Regional State Committee, to work with outside counsel on FERC dockets involving SPP. The PUC also said it would intervene in two FERC dockets:
The Louisiana Public Service Commission’s complaint against Entergy Services and the corporation’s five operating companies alleging they failed to include 100% of the costs of Entergy’s transmission control centers in MISO’s Attachment O formula rate (EL18-201). The PSC said Entergy’s failure to bill MISO for all of the costs would force “native load customers to cross-subsidize the use of the Entergy transmission system by third party wholesale customers.”
East Texas Electric Cooperative’s complaint against American Electric Power subsidiaries Public Service Company of Oklahoma, Southwestern Electric Power Co., AEP Oklahoma Transmission and AEP Southwestern Transmission. The co-op alleges the 10.7% base return on common equity in the AEP West companies’ formula transmission rates is unjust and should be reduced (EL18-199).
A 4.5-MW biomass power generator in Claremont, N.H., will refund ISO-NE capacity payments it wrongly accepted for nine months following the plant’s closure in September 2013 and pay a $250,000 civil penalty under a settlement approved by FERC on Friday (IN18-10).
The commission accepted a stipulation and consent agreement between its Office of Enforcement and Wheelabrator Technologies under which the company will disgorge $107,231.34 in capacity payments and interest.
Claremont energy-from-waste facility | Stuart B. Millner & Associates (SBMA)
Enforcement began its investigation in March 2015 following a referral from the RTO. “Claremont subsequently responded to data requests and requests for investigative testimony, and demonstrated cooperation during the investigation,” the commission said.
Following the Claremont facility’s closure, ISO-NE continued to issue monthly capacity payments for a year in exchange for Claremont’s continuing obligation to supply capacity while the facility was inoperable. The RTO later clawed back the July to October 2014 payments through its Tariff-based reconciliation process.
Public Service New Hampshire (now part of Eversource Energy) previously purchased Claremont’s generation and operated as its lead market participant and asset owner, managing Claremont’s participation in the Forward Capacity Auctions (FCAs) and receiving the payments issued by ISO-NE. On Dec. 1, 2013, PSNH transferred Claremont’s market participant status to Wheelabrator North Andover, which operates a generation facility in North Andover, Mass., and, as of that date, began receiving capacity payments on Claremont’s behalf.
At the time, Wheelabrator management did not fully understand its obligation to shed its capacity supply obligations for FCA 4 (June 2013 to May 2014) and FCA 5 (June 2014 to May 2015) and continued to collect capacity payments for the closed Claremont facility, the commission said.
“Accordingly, Claremont did not successfully shed those obligations. Claremont did shed its obligation for FCA 9 through a non-price retirement request. Claremont’s obligations in FCA 8 were eventually unwound by ISO-NE after it discovered Claremont’s permanent closure,” the commission said.
Wheelabrator’s compliance measures were insufficient to identify the violation, the commission said. The company also agreed to submit annual reports for two years on the progress of its recently implemented compliance measures and any new incidents of noncompliance.
WASHINGTON — NERC CEO Jim Robb is a chemical engineer who learned the electric industry as a McKinsey consultant in California in the 1990s.
“So I learned the industry much more from a business and strategic angle than coming up through technology, operations and planning,” he said Thursday during an hourlong press conference scheduled to mark six months on the job for Robb, who was previously CEO of the Western Electric Coordinating Council. (See NERC Names WECC Chief to Top Post.)
“I’m … not an electrical engineer. … I’m never going to present myself as the smartest guy in the room on any technical topic,” he said. “I think the reason the NERC trustees chose me for this job was my ability to put the right set of people together to work on the right set of issues at the right time.”
Robb, who was tapped to replace long-time CEO Gerry Cauley, met with the press at NERC’s D.C. office, which houses about 30% of the organization’s employees, including its legal, enforcement and communications staffs and the Electricity Information Sharing and Analysis Center (E-ISAC). Robb said he spends most of his time at NERC’s Atlanta headquarters but visits D.C. about three or four times a month. (See related story, NERC Chief Sees Need for Inverter, Fuel Assurance Standards.)
Robb said NERC has a good foundation, citing the long-term strategic plan developed over the last 18 months and its four-year effort to transition to a risk-based approach, the Reliability Assurance Initiative (RAI).
The RAI initiative moved NERC away from the “one size fits all, check the box” approach of the past, Robb said.
Instead of auditing all registered entities on a three-year cycle, NERC and its Regional Entities are focusing on the most critical standards. NERC also has identified about 20% of its requirements as candidates for retirement.
NERC is also narrowing its focus on the entities that present the biggest risks to the system, based on their scale, location and the neighbors with whom they are connected. The organization’s staff now has power to change their audit scope on site if they encounter unexpected issues.
“It’s much more tailored to the individual company, its risk posture and its historical performance,” Robb said. “I think when we first rolled this out, industry thought, ‘This is great. This is going to be much less [regulation].’ And in fact, the experience has been all over the board. There’s some entities that would say, ‘Boy, we’re seeing a lot more of you than we’d like.’ And there are a few that we have had a much lighter touch on.
“We have to maintain rigor at all times. While we’ll disproportionally focus our time on and attention on the key risks and issues of the moment, we can’t lose sight of all the other stuff that goes on,” he added, mentioning criticism the Federal Aviation Administration received over its inspection practices in April following a fatal Southwest Airlines engine failure caused by cracked fan blades. “I don’t want to go through that,” he said.
Among Robb’s priorities are improving the consistency in how standards are implemented across regions, long a source of industry complaints, and improving the work of the ISAC.
Electricity Information Sharing and Analysis Center (E-ISAC) | NERC
The ISAC effort is being led by Bill Lawrence, a NERC veteran who led the GridEx IV exercise in 2017. Lawrence was appointed in August as chief security officer, replacing Marcus Sachs, who resigned last December. RTO Insider reported that Sachs was forced out because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the ISAC’s planned expansion. (See NERC Parts Ways with Chief Security Officer.)
“The ISAC really has not performed up to expectations,” Robb said. “Over the last couple years we, and the Electricity Subsector Coordinating Council’s Member Executive Committee, worked with Bill and others to put real rigor around the strategic role of the ISAC. … The ISAC is really designed to [provide] a service function for the industry. It’s not meant to be an idea lab.”
Robb said the ISAC faced challenges in “sanitizing” confidential information it receives and converting it to actionable intelligence.
The ISAC will double its staffing to “build [a] very strong analytical capability” and create a 24/7 watch operation, Robb said. The ISAC is now staffed only during normal business hours, although there is a NERC officer on duty around the clock.
The Cybersecurity Risk Information Sharing Program (CRISP), which is funded by industry and the Department of Energy and managed by the ISAC, is now monitoring utilities representing about 75% of electric meters to identify hackers seeking to penetrate the companies.
“The risk of a major outage as a result of one of these [attacks] is very low — but not zero,” Robb said. “And given the havoc that would result, we need to always be vigilant and staying way ahead of the curve, and I think we are. I think our system is designed with so much security built in, through the standards, through the isolation of operating systems from enterprise systems, that it would be very, very unlikely that a foreign entity or a malicious actor of any type would be able to create a catastrophic kind of cascading issue on the grid. Not zero, but very unlikely.”
VALLEY FORGE, Pa. — PJM’s initiative to revise how its energy market is constructed continued down the rabbit hole last week with a complex discussion about the timing of procuring reserves.
At Wednesday’s meeting of the Energy Price Formation Senior Task Force, the Independent Market Monitor’s Catherine Tyler suggested revising the operating reserve demand curve (ORDC) to compare the value of purchasing reserves now to fill potential shortages later versus purchasing them later during the peak hours of the day.
Tyler explained that this level of analysis could determine the value of reducing the probability of a reserve. Hung-po Chao, PJM’s chief economist, agreed the idea merits consideration and that “the PJM team has been struggling with that” idea.
FirstEnergy’s Jim Benchek questioned the Monitor’s assumption that the relationship between the price for reserves now and the price for reserves later would be linear.
“That seems like a pretty big leap of faith,” he said.
PJM’s Patricio Rocha-Garrido explained the RTO’s justification for its recommendation of a 30-minute reserve product, which he said would account for all the time necessary to dispatch a resource and have it be ready to operate if necessary. Security-constrained economic dispatch (SCED) cases are solved 10 minutes prior to being implemented, and units that are assigned reserves have 10 minutes after a case is implemented to be online, so that accounts for 20 minutes, Rocha-Garrido said. The additional 10 minutes would cover SCED cases that are completed up to 14 minutes ahead and the additional output assigned units could provide past their assignments, if not for their ramping constraints.
“It kind of sounds like fudging the numbers more than it’s based on anything,” she said. “You are increasing the looking forward time span such that there is more forecast uncertainty, increasing the probability of a shortage and therefore the price.”
“Obviously, I wouldn’t describe it in those terms,” Rocha-Garrido said. “We’re trying to capture the mathematical value … and not dismiss it completely.”
PJM’s Anthony Giacomoni provided market simulations using the RTO’s proposed revisions, which would consolidate Tier 1 and Tier 2 synchronized reserves and implement a downward-sloping ORDC. The simulations found that a net annual increase of $250 million to $800 million in load costs would be shifted from other areas, such as uplift, into the energy market, creating a $1 billion annual increase in energy market revenues.
WASHINGTON — NERC CEO Jim Robb is a chemical engineer who learned the electric industry as a McKinsey consultant in California in the 1990s.
“So I learned the industry much more from a business and strategic angle than coming up through technology, operations and planning,” he said Thursday during an hourlong press conference scheduled to mark six months on the job for Robb, who was previously CEO of the Western Electric Coordinating Council. (See NERC Names WECC Chief to Top Post.)
“I’m … not an electrical engineer. … I’m never going to present myself as the smartest guy in the room on any technical topic,” he said. “I think the reason the NERC trustees chose me for this job was my ability to put the right set of people together to work on the right set of issues at the right time.”
Robb, who was tapped to replace long-time CEO Gerry Cauley, met with the press at NERC’s D.C. office, which houses about 30% of the organization’s employees, including its legal, enforcement and communications staffs and the Electricity Information Sharing and Analysis Center (E-ISAC). Robb said he spends most of his time at NERC’s Atlanta headquarters but visits D.C. about three or four times a month.
Robb said NERC has a good foundation, citing the long-term strategic plan developed over the last 18 months and its four-year effort to transition to a risk-based approach, the Reliability Assurance Initiative (RAI).
The RAI initiative moved NERC away from the “one size fits all, check the box” approach of the past, Robb said.
Instead of auditing all registered entities on a three-year cycle, NERC and its Regional Entities are focusing on the most critical standards. NERC also has identified about 20% of its requirements as candidates for retirement.
NERC is also narrowing its focus on the entities that present the biggest risks to the system, based on their scale, location and the neighbors with whom they are connected. The organization’s staff now has power to change their audit scope on site if they encounter unexpected issues.
“It’s much more tailored to the individual company, its risk posture and its historical performance,” Robb said. “I think when we first rolled this out, industry thought, ‘This is great. This is going to be much less [regulation].’ And in fact, the experience has been all over the board. There’s some entities that would say, ‘Boy, we’re seeing a lot more of you than we’d like.’ And there are a few that we have had a much lighter touch on.
“We have to maintain rigor at all times. While we’ll disproportionally focus our time on and attention on the key risks and issues of the moment, we can’t lose sight of all the other stuff that goes on,” he added, mentioning criticism the Federal Aviation Administration received over its inspection practices in April following a fatal Southwest Airlines engine failure caused by cracked fan blades. “I don’t want to go through that,” he said.
Among Robb’s priorities are improving the consistency in how standards are implemented across regions, long a source of industry complaints, and improving the work of the ISAC.
The ISAC effort is being led by Bill Lawrence, a NERC veteran who led the GridEx IV exercise in 2017. Lawrence was appointed in August as chief security officer, replacing Marcus Sachs, who resigned last December. RTO Insider reported that Sachs was forced out because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the ISAC’s planned expansion. (See NERC Parts Ways with Chief Security Officer.)
“The ISAC really has not performed up to expectations,” Robb said. “Over the last couple years we, and the Electricity Subsector Coordinating Council’s Member Executive Committee, worked with Bill and others to put real rigor around the strategic role of the ISAC. … The ISAC is really designed to [provide] a service function for the industry. It’s not meant to be an idea lab.”
Robb said the ISAC faced challenges in “sanitizing” confidential information it receives and converting it to actionable intelligence.
The ISAC will double its staffing to “build [a] very strong analytical capability” and create a 24/7 watch operation, Robb said. The ISAC is now staffed only during normal business hours, although there is a NERC officer on duty around the clock.
The Cybersecurity Risk Information Sharing Program (CRISP), which is funded by industry and the Department of Energy and managed by the ISAC, is now monitoring utilities representing about 75% of electric meters to identify hackers seeking to penetrate the companies.
“The risk of a major outage as a result of one of these [attacks] is very low — but not zero,” Robb said. “And given the havoc that would result, we need to always be vigilant and staying way ahead of the curve, and I think we are. I think our system is designed with so much security built in, through the standards, through the isolation of operating systems from enterprise systems, that it would be very, very unlikely that a foreign entity or a malicious actor of any type would be able to create a catastrophic kind of cascading issue on the grid. Not zero, but very unlikely.”
AUSTIN, Texas — ERCOT stakeholders last week granted Southern Cross Transmission’s (SCT) request to create a new market participant category for DC tie operators after months of inaction.
The Technical Advisory Committee on Sept. 26 unanimously endorsed a Nodal Protocol revision request (NPRR857) and an accompanying change to the Nodal Operating Guide (NOGRR177). Together, the changes create a “direct current tie operator” role that will clarify “obligations specific to those entities that operate DC ties” as distinct from those of transmission service providers (TSPs), who currently own all DC ties in ERCOT.
SCT was unable to qualify as a TSP because it will not own transmission facilities under the Texas Public Utility Commission’s jurisdiction. Pattern Development is pushing the proposed HVDC transmission project in East Texas that would be capable of shipping more than 2 GW of energy between the Texas grid and Southeastern markets. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)
The revision also requires any TSP that operates a DC tie to secure additional registration as a DC tie operator.
Before the change can be implemented, NPRR857 requires SCT to issue Oncor a notice to proceed with construction of the facilities and provide the financial security required to fund the interconnection facilities. SCT has already signed an interconnection agreement with Oncor.
Under a separate memorandum of understanding with ERCOT, SCT agreed to cover all Protocol revision costs and any system change costs necessary to implement NPRR857. Staff have estimated a budgetary impact of up to $700,000.
The NPRR had been tabled since May’s TAC meeting, when SCT requested a delay in an attempt to increase the market’s understanding of the revision. (See “Staff Again Delays Vote on Amendment, Bylaw Revisions,” ERCOT Technical Advisory Committee Briefs: May 24, 2018.)
Cratylus Advisors’ Mark Bruce, who represents Pattern Development before the TAC, said SCT was ready to move forward with the change requests, but it was waiting for ERCOT’s determination of which market segment a DC tie operator should be placed in for governance purposes. That question is yet to be resolved.
Bruce said ERCOT comments filed Sept. 19 “address everything that was raised previously at TAC.”
ERCOT built on NPRR857 to make it clear SCT will bear the cost of implementing the change and added the criteria necessary to begin its implementation. The grid operator will issue a market notice before beginning the project, and another before NPRR875’s implementation.
The change addresses one of 14 directives the PUC set for ERCOT before energizing the SCT project (Project No. 46304).
TAC Approves First PUC Directive Related to DC Ties
Stakeholders also approved the first ERCOT determination in response to the PUC’s directives, but not before editing ISO staff’s language.
In directive 10, the commission ordered ERCOT to decide whether pricing changes are necessary within the market during emergencies to avoid DC tie flows “adversely affecting price formation … or otherwise causing outcomes inconsistent with a properly functioning energy market.”
TAC changed ERCOT’s original determination (“No market changes are needed to address pricing issues.”) to: “Although ERCOT staff recognizes potential price formation issues, ERCOT staff has identified no need for additional market changes at this time.”
Members argued staff’s original determination did not accurately reflect discussions within the Wholesale Market Subcommittee (WMS) and the Qualified Scheduling Entity Managers Working Group (QMWG). Both groups eventually endorsed ERCOT’s determination, which noted that stakeholders had previously considered pricing issues.
WMS Chair David Kee of CPS Energy said a staff white paper approved by stakeholders did not capture the history of the issues.
Staff said it determined that actions related to DC ties could “adversely affect” price formation during both emergency and normal conditions. They noted stakeholders have considered these issues while developing NPRRs related to the operating reserve demand curve’s (ORDC) price adder and the real-time online reliability deployment price adders.
Staff said there is no need to revise the NPRRs with another change request but said they will engage in stakeholder discussions should an NPRR be submitted or the PUC issues another directive.
QMWG Chair Eric Goff of Citigroup Energy said a market participant he did not identify plans to file an NPRR making changes to price adders and the ORDC. Goff’s abstention was the only vote the determination did not receive.
“That view may not jibe with the stakeholders’ view, but we think it’s important for the board to evaluate those opinions,” ERCOT’s Nathan Bigbee said. “We view this as an ERCOT staff artifact, but we want to give you a chance to see our input.”
The white paper and determination will be presented for the Board of Directors’ approval at its Oct. 9 meeting.
TAC Endorses $53.3M Economic Project in West Texas
The committee endorsed Wind Energy Transmission Texas’ (WETT) Bearkat area transmission project in West Texas, which could become ERCOT’s first economic project in three years.
The project, which will be up for board approval in October, addresses congestion on a 138-kV line near Odessa, which is burdened with 1.5 GW of operational and planned wind generation. It consists of two new 345-kV bays and a 27-mile, 345-kV single-circuit line on double-circuit-capable structures.
The Bearkat project had a $69.9 million price tag when WETT submitted it to the Regional Planning Group last year. ERCOT staff’s independent review whittled the cost down to $53.3 million by recommending one of the least-cost 345-kV options, saying it provides a high transfer limit and “relatively good overall net societal benefits.”
The review evaluated nine upgrade alternatives, all of which passed the grid operator’s economic-planning criteria: Annual production cost savings must be equal to or greater than the project’s first year annual revenue requirement, assumed to be 15% of the capital cost.
Bearkat has a savings-to-cost ratio of 60% and is projected to produce $400 million in 30-year net savings.
The TAC will likely move its 2019 meetings from Thursdays to Wednesdays to avoid conflicts with the PUC’s open meetings. TAC Chair Bob Helton said the change will also allow committee members to devote more attention to several PUC dockets that will “create issues in the wholesale market.”
Just Energy’s Blakey Confirmed as RMS Chair
Committee members unanimously confirmed Just Energy’s Eric Blakey as chair of the Retail Market Subcommittee, which serves as a forum to resolve retail market issues.
The committee’s Reliability and Operations Subcommittee (ROS) will choose its new chair on Oct. 11. The ROS develops, reviews and maintains operating guides and planning criteria.
Other Approvals
The TAC also approved five NPRRs, two revisions to the Nodal Operating Guide (NOGRR), two Other Binding Document revision requests (OBDRR) and two changes to the Planning Guide (PGRRs):
NPRR845: Incorporates numerous revisions to the reliability-must-run process, including standardizing the standby cost in terms of dollars per hour instead of dollars per megawatt; adjusting availability metrics used in settlements to the current operating plan rather than the availability plan; clarifying a resource’s post-RMR status and requiring an entity to submit a resource-notification change no later than 60 days before an agreement’s conclusion; allowing ERCOT to retain a mutually agreeable third party to help evaluate submitted RMR budgets; and modifying the RMR agreement to require detailed budgeted costs with or without capital expenditures.
NPRR869: Requires generators over 1 MW within a private use network (PUN) to provide modeling information to ERCOT if they are not: registered with the PUC as a power generation company; part of a PUN with more than one connection to the ERCOT grid; or registered to provide ancillary services. The change includes a netting exemption for a qualifying facility that is a small power production facility and provides energy to a customer behind a single point of interconnection. It also deletes a reference to the now-expired System Benefit Fund.
NPRR880: Requires ERCOT to publish shift factors for PUN settlement points for the real-time market, as is currently done in the day-ahead market.
NPRR883: Removes the real-time reliability deployment price adder from the real-time settlement point price to avoid double payment when resources have received an ancillary services assignment.
NPRR888: Clarifies the four-coincident-peak (4-CP) adjustment methodology that was implemented in conjunction with NPRR830.
NOGRR180: Removes “governor dead-band” and “governor droop settings” requirements for combined cycle steam turbines.
NOGRR181: Ensures consistency between the ERCOT and NERC requirements regarding black start plans. Because ERCOT has to review each transmission owner’s plan within 30 days of receipt, it must receive the plans for each year by Nov. 1 of the preceding year to complete its annual study.
OBDRR007: Changes the ORDC methodology to account for the curtailment of solar PV resources. Solar generation had been excluded since the ORDC was implemented in 2014.
OBDR008: Makes ERCOT’s procedure for identifying resource nodes consistent with NPRR890, which aligns price-calculation formulas with ERCOT systems calculation of the real-time LMP at a logical resource node for an online combined cycle generation resource. NPRR890 has cleared the Protocol Revisions Subcommittee.
PGRR063: Outlines the process for evaluating the reliability impact of transmission projects of 100-kV or above that are expected to be in service before the next Regional Transmission Plan’s completion but that were not included in the current plan, a Regional Planning Group project submission, or a generation interconnection or change-request study.
PGRR064: Requires resource entities to verify that dynamic devices used for reliability reflect their operating characteristics.
MISO said last week it will approve New Orleans’ request to make the city a cost allocation zone but is deferring action on an interregional cost-sharing plan advanced by transmission owners.
In a letter signed by City Councilmember Helena Moreno, New Orleans asked MISO to create a standalone cost allocation zone for the city, pointing to FERC’s policy that project costs be allocated “roughly commensurate” with estimated benefits and that non-beneficiaries not be required to pay for them.
“MISO’s analysis has demonstrated that cost allocation on a more granular level within the state of Louisiana will improve the alignment of benefits and costs, consistent with MISO’s objectives for cost allocation reforms,” the city said.
The request involves creating an Entergy New Orleans transmission pricing zone. Director of Strategy Jesse Moser said the zone will not contain overlapping regulatory jurisdictions.
MISO conducted analyses to determine whether a New Orleans zone would contain enough generation and load to calculate benefits and result in better alignment of the costs and benefits for economic projects under the Transmission Expansion Plan.
“The short answer is ‘yes,’” Moser said during a Sept. 27 Regional Expansion Criteria and Benefits Working Group meeting. He said example calculations show MISO can isolate benefits and costs for New Orleans.
“We do plan to make a filing some time in the middle of October … to effectuate this change,” he said.
How Small?
Stakeholders asked MISO how small it’s willing to make cost allocation zones, with some saying they thought the RTO favored larger cost allocation zones.
MISO hasn’t established how small is too small, Moser responded.
“We could have something that’s too small. I don’t think we’ve put any definition around that yet,” Moser said. “It’s going to be incremental steps, and I think this [New Orleans] zone is a step in that direction.”
The current 11 cost allocation zones, based on the historic grouping of transmission pricing zones by state jurisdiction, resemble the 10 local resource zones used in the annual capacity auction. MISO earlier this year separated its Texas territory into a distinct cost allocation zone at the request of regulators.
Moser said MISO’s smallest cost allocation zone currently contains about 300 to 400 MW of generation. He added that while the RTO will not create any new cost allocation zones beyond New Orleans ahead of its planned cost allocation filing with FERC, it may revisit the possibility of creating new, smaller zones in the future.
“I think it’s something we’re going to come back to. I don’t think we’re done with this level of granularity,” Moser said.
As part of its cost allocation overhaul, MISO said it would look into the possibility of more specific zones. The RTO has proposed eliminating a footprint-wide postage stamp rate and lowering its current threshold for market efficiency projects from 345 kV to 230 kV. It will also add new benefit metrics to judge a project’s eligibility for cost allocation, including consideration for projects that defer or avoid other reliability transmission projects and a benefit for projects that reduce flows on the contract path on SPP transmission linking MISO’s North and South regions. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)
Speaking before the Board of Directors in September, MISO Vice President of System Planning Jennifer Curran said the RTO’s cost allocation proposal had determined a good way to estimate regional benefits considering the “various interests of stakeholders.”
“This is a very thorny issue here. You’re talking about money,” Director Mark Johnson said. “The entire MISO team needs to be commended for this effort.”
Alternate Interregional Proposal
However, most members of MISO’s Transmission Owners sector are seeking an alternative to the RTO’s plans for interregional project cost allocation.
A majority of TOs, including those with Section 205 filing rights, have formally requested that MISO consider their alternative approach for projects developed jointly with SPP and PJM.
The proposal stipulates that for interregional projects located in both RTOs through tie lines — or wholly within MISO — MISO would allocate costs to each RTO based on adjusted production cost benefits outlined in joint operating agreements. To allocate interregional costs within MISO, benefiting cost allocation zones would share costs for projects 230 kV and above, and the transmission pricing zone where the project is located would take on costs of projects below 230 kV down to 100 kV.
For interregional projects located wholly outside of MISO in either SPP or PJM, RTO costs would be divvied up according to adjusted production cost, with MISO’s allocation spread across benefiting cost allocation zones for projects 230 kV and above. However, for 100- to 229-kV projects, costs would be divided based on a line outage distribution factor (LODF) to determine the local transmission prizing zone beneficiaries. A LODF measures the change in flow on a facility stemming from the outage of a new project facility.
The RTO has said it wants consistency in project requirements along its seams with SPP and PJM, citing that reason in June when it proposed cost sharing 100-kV and above interregional projects along both the PJM and SPP seams. At the time, more than 20 MISO TOs said they opposed the 100-kV cost sharing threshold on SPP interregional projects because the MISO-SPP seam is lengthier with sparser load density than PJM. They also argued the seam is a better fit for higher-voltage projects, which can carry electricity farther. (See MISO to Lower SPP Interregional Project Thresholds.)
Moser said MISO is not yet taking a stance on the TOs’ proposal, waiting until it can work out numerical examples for hypothetical projects under the proposal. He said the RTO might not take an official position until early November.
“We appreciate the work of the owners,” Moser said. “It’s not everyone in the TO community, but it does represent a [Section] 205 filing majority, notwithstanding other filing rights that could be exercised in that community.”
Speaking for the TOs, attorney Wendy Reed thanked MISO for considering their proposal and said members hope they can negotiate with the RTO to avoid filing a competing cost allocation proposal with FERC.
Stakeholders at the meeting appeared divided on the proposal. LS Power’s Pat Hayes and Northern Indiana Public Service Co.’s Clark Gloyeske said they still supported MISO cost sharing down to 100 kV on interregional projects, though Mississippi Public Service Commission Counsel David Carr expressed support for the TO proposal. MISO asked for written stakeholder feedback on the proposal through Oct. 16.
MISO last week announced plans to update its interconnection queue procedures to allow multiple projects to interconnect at one point on the system. It also said it will study ways to bring hybrid projects into the process.
At the same time, the RTO is receiving stakeholder pushback on previous proposals to increase the queue’s milestone fees and merge its Interconnection Process Task Force (IPTF) with the Planning Subcommittee.
Speaking at a Sept. 25 IPTF meeting, MISO engineer Tim Kopp said the RTO now thinks multiple projects can share a single interconnection point, but it wants a shared-use agreement struck early in the process and separate metering for each interconnecting facility. He said MISO plans to make Tariff changes that will go before the Planning Advisory Committee.
2 projects 1 POI | MISO
MISO’s current policy allows only one project per point of interconnection, but market participants have contended they can decrease costs by sharing a single point of interconnection.
The RTO’s plan would require interconnection customers to signal their intention of a multiparty arrangement when they submit applications to join the queue. Before entering the queue, the customers, transmission owner and MISO itself would sign an agreement that would be referenced in the projects’ generator interconnection agreement. Kopp said the agreement is needed to prevent customers from changing use arrangements while advancing through the queue.
“We don’t want to introduce delays with this process because we’re waiting on interconnection customers to negotiate” use agreements, Kopp said.
MISO expects joint requests to increase in the future as smaller projects that only use a small amount of interconnection service proliferate on the grid, he said.
Hybrids in the Queue
MISO staff said minimal revisions to the Business Practices Manuals are required to accommodate hybrid interconnection configurations within the queue study process.
The RTO expects it will most commonly study storage alongside wind and solar generation, as well as wind and combined cycle configurations and wind and solar configurations. Wind and solar have somewhat complementary roles in the MISO footprint; wind tends not to kick up full-force during the sunniest periods of the day.
MISO also said it would consider other configurations at stakeholder request.
“We’re open to review on what stakeholders are going to address,” said Neil Shah, MISO manager of resource interconnection.
Draft rules show MISO would largely use its existing BPM language for other resource types, though it said it will evaluate hybrid fuel dispatch predictions, used in its five-year-out power flow analysis, on a case-by-case basis in ad hoc meetings.
During a Sept. 24 Energy Storage Task Force meeting, Xcel Energy and NextEra Energy proposed that MISO phase in hybrid formats involving storage over time, with hybrid market rules created in the short term. In the longer term, the RTO should devise plans for optimizing charging, which would be handled either by the RTO or market participants, the companies said. Beyond that, MISO would create a flexible participation model where hybrid unit owners can toggle among which ancillary and energy services they provide.
NextEra’s Holly Carias said MISO and stakeholders would have to establish how to best optimize intermittent resource hybrids like wind and solar so they charge and discharge at the most economic times. MISO’s compliance with Order 841 will not involve storage optimization. (See “No Optimization Yet,” MISO Closing in on Storage Participation Plan.)
Energy Storage Task Force Chair John Fernandes said the issue could be ripe for a white paper. MISO’s Steering Committee this month recommended the task force focus on creating white papers for technical storage issues. (See New Direction for MISO’s Energy Storage Task Force.)
MISO to File Queue Changes
Stakeholders are skeptical about MISO’s final milestone modifications aimed at speeding up the slow-moving, 90-GW interconnection queue. While the RTO’s proposal for more stringent site control appears unchallenged, its plan to revise the milestone fee structure is drawing ire. (See MISO to Tweak Queue Rules on Site Control, Project Fees.)
The latest version of the plan calls for the last of three milestone payments in the queue to be reduced to 10% of network upgrades, down from an earlier proposal of 20%. However, MISO plans to raise its first milestone payment from $4,000/MW to $10,000/MW, and some stakeholders say the increase is too steep. They question the RTO’s reasoning for more than doubling the rate.
Tradewind Energy’s Derek Sunderman said MISO was unnecessarily focusing on the milestone fee structure when it should be working to expedite its own study process.
“I would argue that MISO really needs to focus on its study process because this is getting ridiculous. … I don’t think MISO is listening to stakeholders,” Sunderman said.
MISO Resource Utilization Director Vikram Godbole said the current low milestone fees don’t do enough to deter interconnection customers from entering speculative projects that could harm the economic viability of ready projects.
“Our record does not indicate good progress,” Godbole said of the 90-GW queue, arguing for the milestone change.
Other stakeholders said that the active queue will likely slow down after production tax credits for new wind generation expire in 2020.
But Rhonda Peters of Clean Grid Alliance (formerly Wind on the Wires) said the 35 GW of prospective solar generation currently in the queue suggests that solar will become the new resource that keeps the queue busy.
Shah asked for stakeholder feedback on the revised plan by Oct. 9. He said MISO expects to have a final version of the plan in time for review at the Oct. 17 PAC meeting.
In-house Model Development
Shah added that, contrary to some opinions, MISO is focusing on speeding up its study process.
One example: MISO will start building queue study models in-house, according to principal engineer Cody Doll, who noted the RTO currently hires third-party consultants to build the models used in the definitive planning phase of the queue.
“Currently, there seems like there are a ton of delays in our model building,” Doll said. “We’re doing this to gain control of the process.”
Doll said the new process will help MISO maintain better records of the queue process and should cut down on errors made when entering information. It should also shorten MISO’s current 30-day model review period, which can stretch into months depending on whether the RTO uncovers modeling errors.
“We’ll still have the review period, but we’re hoping it’ll be a week or so,” Doll said.
End of IPTF?
Meanwhile, MISO is proposing to end the IPTF and fold its discussions and duties into the Planning Subcommittee. The task force has largely completed its queue revisions, but some stakeholders say more work remains and pointed out that stakeholders attending the IPTF have voted to transform it into a working group. In MISO’s stakeholder structure, working groups are more permanent than task forces, which have an expected sunset date.
Several stakeholders said MISO didn’t provide enough warning to stakeholders before bringing the idea forward at the Sept. 26 PAC meeting, with some suggesting the RTO was trying to subvert the stakeholder process by not posting the discussion as an agenda item. WEC Energy Group’s Chris Plante said he did not have time to introduce the idea to the Transmission-Dependent Utilities sector ahead of the meeting and said he was “disappointed in MISO’s process.”
MISO Executive Director of Resource Planning Patrick Brown said moving the IPTF into the permanent Planning Subcommittee will cut down on identical presentations at the two groups and will result in more comprehensive discussion because interconnection topics will take place alongside transmission planning discussions. It will “enable a more holistic approach to planning,” Brown said.
“We’ll have a broad range of stakeholders involved in the conversation,” he added.
MISO staff promised more discussion in October on how to merge the IPTF’s charter into that of the PSC.
FERC last week approved MISO’s plan to cut some duplicate analyses from the first phase of its generation interconnection queue.
The approval means MISO can remove its dynamic stability, short-circuit and affected-system analyses from the first phase of the queue’s definitive planning phase (DPP) (ER18-2049). The RTO said the procedures are currently repeated once a project hits the second phase of the DPP.
MISO staff have said the changes would help speed along the overbooked, 90-GW interconnection queue, a sentiment shared by the RTO’s Transmission Owners sector in comments on the filing. (See “Studies Reduction,” MISO Proposal Aims to Speed Up Queue Process.)
FERC agreed with that assessment: “We find that MISO’s proposed Tariff revisions will streamline DPP Phase I and likely reduce the duration of delays experienced by interconnection customers in MISO’s interconnection queue.”
The commission also noted some stakeholders’ position at an April technical conference that an affected-system analysis in each of the three DPP phases is a contributing factor to queue delays. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.) MISO has also said that results of its first affected-system studies are often subject to change later, given the uncertainty of the early information.
Early last week, MISO’s Neil Shah said if FERC didn’t approve the changes, the RTO would continue using its current study process that includes the redundant studies.
