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September 30, 2018February 12, 2024

ERCOT Technical Advisory Briefs: Sept. 27, 2018

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.

Staff’s white paper explained its determination.

“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 review took into consideration Lubbock Power & Light’s pending integration into ERCOT and the recently approved Far West Transmission Project. (See ERCOT Board Approves West Texas Transmission Project.)

TAC to Move 2019 Meetings to Wednesday

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.

September 30, 2018

MISO to Create NOLA Cost Allocation Zone

By Amanda Durish Cook

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.

miso nola cost allocation zone — Jesse Moser | *© RTO Insider*

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.

September 30, 2018

MISO Queues up Interconnection Options

By Amanda Durish Cook

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.

miso interconnection queue iptf — 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.

September 30, 2018

MISO Plan to Reduce Queue Studies Gets FERC Nod

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 FERC interconnection queue transmission studies — | *© RTO Insider*

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.

— Amanda Durish Cook

September 30, 2018

NERC Chief: Inverter, Fuel Assurance Standards Needed

By Rich Heidorn Jr.

WASHINGTON — NERC CEO Jim Robb said Thursday he is pushing for new reliability standards to address fuel assurance concerns and ride-through settings for inverters on solar generation and storage.

nerc jim robb inverters fuel assurance — Jim Robb, NERC CEO (right) with Kimberly Mielcarek, senior director of communications. | *© RTO Insider*

“I think a standard will be called for” on inverters, Robb said during a press conference at NERC’s D.C. office marking six months since he took the organization’s helm. “I feel the same way about fuel assurance. But my eyes are wide open to the challenges in crafting those appropriate [requirements] and figuring out which entities should be accountable for them.” (See related story, New NERC Chief Not ‘Smartest Guy in the Room.’)

NERC has issued two alerts on inverters, one after the 2016 Blue Cut wildfire near Los Angeles caused transmission line faults and disconnected 1,200 MW of solar resources, and a second following a fire in spring 2018. Both were Level II alerts, which required registered entities to respond to NERC’s recommendations and answer questions about solar generation in their footprints and how they plan for the loss of the resources.

NERC is now finalizing a reliability guideline to ensure inverters are configured “so they play nicely with the rest of the system,” Robb said. “An inverter can do almost anything you want it to do. You just have to tell it what to do.”

Robb said the issue is a concern not only in California and the Southwest but also in North Carolina, Massachusetts and Texas, where solar penetration is rising. Battery storage also uses inverters and presents similar issues, he said.

“The issue around the standard that we’re currently struggling with is that right now all of our standards … are technology-agnostic and fuel-agnostic,” Robb said. “So, this would be the first that we would put in for a specific technology. And not everyone’s embracing that notion, so we have some work to do.” (See Solar Inverter Problem Leads CAISO to Boost Reserves.)

Fuel Assurance Standard

The shift from baseload coal and nuclear generation to variable resources and natural gas also justifies a reliability standard, Robb said.

“Loads are becoming much less certain than what we’ve had in the past. In fact, to be perfectly honest, we don’t know what the load curve of California looks like anymore because so much of it is masked by the distributed solar panels on peoples’ roofs,” he said. “We have a lot of tools and a lot of rules … we use to operate and manage and plan the system that are all largely based on a 1950s view of the world [that’s not] really true anymore.”

One of the challenges is aligning the natural gas industry’s infrastructure, scheduling policies and modeling to the real-time needs of the electric industry.

“Those [gas] power plant ramp rates are getting steeper and steeper” in the afternoons, when solar generation drops as loads peak, Robb said. “And effectively what we’re seeing is power plants were sucking gas out of the distribution system faster than pipelines could pack it in.”

Although pipelines can provide some storage by increasing pressure in their systems, “what we’re seeing in areas like the Southwest … is some of the pipeline corridors are running 90 to 95% of capacity. So they don’t have the same degree of flexibility they would have had five, 10 years ago.”

In addition, because of the way gas is regulated, “there is really no [one] who can solve these problems with the stroke of a pen,” Robb said.

Natural gas problems are most acute in New England and Florida, which have limited pipeline infrastructure, and California, which has lost most of Aliso Canyon’s storage capacity. (See related story, CAISO Seeks to Extend Aliso Canyon Rules.)

Although NERC’s current standards address planning for contingencies, they are “relatively vague as to how to think about fuel as a contingency,” Robb said.

“So we’re talking through getting a guideline in place that would make clear that any particular entity ought to look at a major pipeline disruption for example [or] a problem on the rail system … and start to factor that into their operating and shorter-term planning.”

Still to be determined is which entities would be subject to a pipeline contingency rule. “The challenge in evaluating the gas system is you need to really look at it over a fairly wide area, probably a bigger footprint than a planning coordinator, certainly a bigger footprint than in individual utility. It might be something that might be best applicable to [a reliability coordinator] but the RCs aren’t really set up to do that kind of planning,” Robb said.

He acknowledged that the industry generally prefers guidelines over standards because the latter can result in enforcement actions. “I choose to think of them as providing great clarity around how things should be done, particularly around these very disparate resources around the system that can interact in ways that don’t contribute to the community event that we call reliability. But it will take us a while to get there.”

Robb also acknowledged that the issue has become politicized by the Trump administration’s efforts to provide price supports for money-losing coal and nuclear generators. “My goal is to make sure that our work remains technically unimpeachable so it’s there to inform people who are making important decisions around these issues but not get drawn into the political and ideological arguments around them.”

September 30, 2018

MISO Contemplates Storage as Tx Reliability Asset

By Amanda Durish Cook

MISO last week floated a relatively simple straw proposal for treating storage as a reliability asset in its annual transmission plan.

The proposal involves no interconnection queue entry, asset registration and day-ahead scheduling notices.

miso reliability asset energy storage — Jeff Webb | *© RTO Insider*

Speaking during a Sept. 26 Planning Advisory Committee meeting, Director of Planning Jeff Webb said the RTO hopes to get a final proposal in place in time for the 2019 MISO Transmission Expansion Plan cycle.

Webb said stakeholders have asked how storage projects providing reliability transmission services will be able to enter the MTEP.

“Well how does any other transmission project get in? It’s proposed as a solution in the planning process,” he said.

Webb explained the projects would be proposed in MTEP as either a baseline reliability project driven by NERC criteria and allocated to local pricing zones, or as an “other” reliability project not eligible for regional cost allocation. If the storage project solves the issue at the lowest cost, it will be included in the annual plan.

He stressed that MISO’s plan only serves to treat storage comparably to other transmission assets, clarifying that storage projects would not necessarily take priority over traditional wires projects because “storage has a lot of hurdles and costs” to overcome.

“There will be opportunities, I think, to use” storage, Webb added.

‘To Queue or not to Queue’

Webb said storage as transmission would not be required to enter the interconnection queue as long as the project will not participate in the energy and ancillary services markets. If a storage asset is planned for both reliability transmission services and market services, the asset must first respond to reliability needs in the transmission market. If MISO doesn’t need the asset for reliability transmission purposes, it would be free to participate in the energy market pursuant to MISO’s future Order 841 compliance plan, provided it has completed the interconnection queue.

The queue is required “if for no other reason than comparability with other resources that the project would be competing with in the energy market,” Webb said.

“There’s a lot of controversy; to queue or not to queue,” he said of stakeholder reactions. He also said opportunities for market participation by storage projects intended for transmission use will vary according to location, noting that, for example, storage located in rural Iowa with few generation options nearby will have different market opportunities than storage added in a large metropolitan area where generation is already abundant.

“So maybe the answer comes down to significance factors: Where and how big?” Webb mused.

Reliability storage projects will be required to complete asset registration to allow MISO to control the asset when it’s required to maintain system reliability. The asset will receive notice of need in the day-ahead schedule and be recalled as needed during the operations day. Like other transmission assets, the storage assets will be price-takers when under RTO instructions.

Webb said MISO hasn’t proposed rules to credit a storage asset’s market revenue against its transmission asset cost recovery. Some stakeholders have said that allowing the two revenue streams would incentivize dual-use storage to the point that transmission reliability is diminished.

Webb said he expects MISO and stakeholders to discuss storage as reliability transmission services through the first half of next year. He noted that MISO could possibly schedule a workshop on the topic in response to stakeholder requests.

September 30, 2018

NERC Chief: Inverter, Fuel Assurance Standards Needed

NERC Chief Sees Need for Inverter, Fuel Assurance Standards

By Rich Heidorn Jr.

WASHINGTON — NERC CEO Jim Robb said Thursday he is pushing for new reliability standards to address fuel assurance concerns and ride-through settings for inverters on solar generation and storage.

“The issue around the standard that we’re currently struggling with is that right now all of our standards … are technology-agnostic and fuel-agnostic,” Robb said. “So, this would be the first that we would put in for a specific technology. And not everyone’s embracing that notion, so we have some work to do.” (See Solar Inverter Problem Leads CAISO to Boost Reserves.)

Fuel Assurance Standard

The shift from baseload coal and nuclear generation to variable resources and natural gas also justifies a reliability standard, Robb said.

One of the challenges is aligning the natural gas industry’s infrastructure, scheduling policies and modeling to the real-time needs of the electric industry.

In addition, because of the way gas is regulated, “there is really no [one] who can solve these problems with the stroke of a pen,” Robb said.

Although NERC’s current standards address planning for contingencies, they are “relatively vague as to how to think about fuel as a contingency,” Robb said.

September 28, 2018

‘Negative Leakage’ from NY Carbon Charge, Study Shows

By Michael Kuser

RENSSELAER, N.Y. — An independent study suggests New York’s effort to price carbon into its electricity market could result in reduced CO₂ emissions from generators in neighboring areas, rather than an uptick due to “carbon leakage,” the state’s Integrating Public Policy Task Force (IPPTF) learned Monday.

That so-called “negative leakage” in other parts of the Eastern Interconnection would be the result of electricity price changes that very slightly favor natural gas over coal generation, analysis by the nonprofit Resources for the Future (RFF) found.

At the IPPTF’s Sept. 24 meeting, RFF’s Dan Shawhan presented the study, which modeled the impact of carbon pricing on emissions and prices in New York and neighboring regions based on expectations for 2025. The group used its own Engineering, Economic and Environmental Electricity Simulation Tool (E4ST) to project effects in New York and throughout the interconnection.

New York’s carbon policy could produce “negative leakage,” reducing emissions not only in New York but in the rest of RGGI and the non-RGGI parts of the Eastern Interconnection. | *Resources for the Future*

In terms of 2025 dollars, the study estimates an environmental benefit of $288 million per year, mostly from a slight reduction in emissions outside New York, and a net total benefit of $279 million per year.

Because New York will have no coal-fired capacity in 2025, less than a quarter of the estimated environmental benefit is from NOx and SO₂ emission reductions, Shawhan said. Estimated SO₂ damage actually increases slightly because a carbon charge would shift some emissions to locations that cause larger estimated health damage per pound emitted.

Excluding the positive environmental benefits, collective end-user costs in New York come in at $562 million per year, equivalent to $3.60/MWh, with a “somewhat smaller profit gain” for New York generators.

The study estimates a 0.9% reduction in generator CO₂ emissions in the state and a 0.2% increase in in-state generation. RFF attributes a 1.1% reduction in New York power sector CO₂ emission intensity primarily to equalizing the CO₂ emission price applied to in-state fossil fuel generators both exempt from and subject to the Regional Greenhouse Gas Initiative. A carbon charge would reduce damage from New York generator emissions by $17.4 million per year. With the RPS still binding in 2025, the study finds no change in the state’s volume of renewable generation due to carbon pricing.

The study estimates an LBMP price increase of approximately $20/MWh in zones A-E, $22/MWh in zones F-I, and $23/MWh in zones J and K, while the renewable energy credit price would drop from $45.88/MWh to $27.28/MWh, and the zero-emissions credit (ZEC) price would plummet from $13.64/MWh to zero.

Upstate nuclear unit revenue would climb under the model from $65/MWh to $67/MWh, while the RGGI price would rise slightly, from $11.28 to $11.90 per ton CO₂.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said: “If one were to rely on your study results to decide whether New York should do this or not, it would be tough to make that decision on a single-year snapshot, so I’m trying to get a feeling for whether your model is likely to produce consistent results over time.”

“I think of this as an approximation of the average effect over the multiyear period … however, it is not exactly the same as what we would get if we simulated each of those years,” Shawhan replied.

Zonal Allocation

The Brattle Group’s Sam Newell presented analysis on carbon revenue allocation — the process of crediting carbon prices back to electricity consumers. The analysis shows the implications of four alternative allocation approaches that NYISO had proposed and provides a spectrum of options along two competing allocation objectives: to align LBMPs with the marginal cost of serving load while avoiding major cost shifts among customers.

NYISO recommends ‘Levelizing Allocation’ because it prioritizes avoiding major cost shifts across zones, despite eliminating an efficient price signal that internalizes the costs of CO2 emissions. | *Brattle Group*

“As soon as you get into debating how best to allocate money, that’s a very difficult discussion,” Newell said.

Newell said transmission constraints into New York City represent one of the key challenges related to allocation.

“So if you add a carbon charge, you’d have a greater increase in LBMPs there than elsewhere, and that’s one of the things we need to account for… and how that can possibly be offset by different allocation approaches,” he said.

All the individual zone results in the study’s appendix reflect nodal modeling, he said. To the extent there are transmission constraints going into Zone J (New York City), the model tries to capture them.

But the model found the biggest constraint “by far” is really across NYISO’s Central-East Interface, “much more than it is going into southeast New York,” Newell said.

“We did the math, and not surprisingly, with the load-share approach, everybody in every zone, whether upstate or downstate or any part of those, gets about $10/MWh” in allocations, Newell said.

To levelize the net effect (what an LSE pays for the carbon component of the LBMP minus the allocated residuals), downstate zones would need to receive about $4/MWh more in allocated residuals than upstate zones, he said.

IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said, “When we would go to do the allocations, there are only two things we can observe: one is the carbon component of the LBMP, and the other is how much money we collected from generators.”

The ISO cannot observe whether a carbon scheme attracted more investment downstate than upstate and thereby lowered capacity prices downstate, lower than the non-carbon component of LBMPs downstate, Newell said.

A carbon charge opens up a bigger gap between the upstate price and the downstate price, and the markets will tend to levelize the impacts somewhat as suppliers respond to and partially undo the price stimulus, he said.

“What are dynamic effects?” Newell said. “That’s the market responding to price signals.”

Seams and MER

Newell also presented analysis on seams, reiterating a presentation he made in April on applying carbon charge border adjustments to the ISO’s external transactions.

Newell backs the ISO in proposing to levy import charges and export credits in such a way that makes the effects of carbon pricing invisible to external transactions, with external resources competing on a “status quo” basis. However, if NYISO were to consider an alternative approach, levying charges based on the emissions associated with transactions, several key concepts would have to be addressed, Newell said.

“What is the relevant rate?” Newell asked. “Is it the average rate of their fleet? No, it is the marginal emissions consequences of taking a transaction from there. That’s how spot pricing is supposed to work — to create efficient marginal incentives in the operating timeframe. So they’re not average emissions; it’s the marginal emissions rate.”

One stakeholder questioned the study’s hypothetical resource shuffling that might result from a “status quo” approach to carbon pricing, saying the ISO has import limits and it’s probably impossible for all of the nuclear generation in PJM to flow in while all the fossil generation in New York state flows out.

“Yes, it can happen,” Bouchez said. “When you look at imports and exports today, in any one hour, it’s almost unheard of to see transactions only going in one direction … physically there are people importing and exporting at the same time on the same interface. What matters are the net flows, which we calculate as the net of the imports and exports.”

Tariq Niazi, ISO senior manager and Consumer Interest Liaison, presented a study summarizing the Brattle report, finding that a carbon charge would reduce CO₂ emissions approximately 3% by 2030, causing only limited fuel switching, and that most emission reductions would result from dynamic effects such as renewable shifts, nuclear retention and price-responsive load.

Speaking of the need to reconcile various reports and their differing cost estimates, Niazi said, “Our focus is to get this NYISO analysis done between now and mid-October, when we plan to come back.”

Brattle will present the final version of its customer impact analysis at the next IPPTF meeting on Oct. 15 at NYISO headquarters, with an additional task force meeting possible in the interim.

September 28, 2018

MISO Utilities Float New Load Forecasting Approach

By Amanda Durish Cook

A new stakeholder-led proposal would require MISO load-serving entities to develop a 20-year base load forecast that includes monthly predictions for energy and non-coincident peaks.

The Coalition of Utilities with an Obligation to Serve in MISO (CUOS), an ad hoc group of MISO utilities and regulators, advanced the plan after the RTO earlier this month requested stakeholder ideas for improving load forecasting.

LSEs must currently provide just two years of monthly forecast data to MISO, but WPPI Energy economist Valy Goepfrich said long-term forecasts the RTO obtains from the Purdue University State Utility Forecasting Group — which are compared against LSE projections — so far “have confirmed the validity of the LSE base load forecasts.”

Under the CUOS plan, the LSEs’ base load forecasts would be applied to MISO’s base case Transmission Expansion Plan (MTEP) future, the “limited fleet change” future. The other futures include a continued fleet change future, an accelerated fleet change future and a future in which distributed and emerging technologies become more widely used in the MISO footprint.

“The CUOS proposal is leveraging the forecasts that LSEs already develop,” Goepfrich explained during a Sept. 26 Planning Advisory Committee meeting. She said the proposal is more cost-effective than continuing to pay Purdue for independent load forecasting.

MISO Planning Advisory Committee in June | *© RTO Insider*

The CUOS proposal would also direct LSEs to provide data on transmission losses, as well as demand served by energy efficiency planning resources, demand resources and behind-the-meter planning resources. LSEs would not be required to provide numbers on demand served by energy efficiency programs and other resources not classified as planning resources. Goepfrich said MISO can continue to use consulting firm Applied Energy Group for distributed resource data predictions in the three other MTEP futures.

The Parable of the Ox

miso lse load-serving entities load forecasting — Trip Doggett at the MISO Market Symposium in August | *© RTO Insider*

Goepfrich referenced an address at this year’s MISO Market Symposium in which RTO Director Trip Doggett cited “The Parable of the Ox,” a story included in James Surowiecki’s book “The Wisdom of Crowds.” The story recounts how in 1906, statistician Francis Galton studied a competition to guess the weight of an ox at a country fair, observing the average guess was accurate to within 1% of the actual weight of the 1,200-pound animal. Doggett used the story to illustrate that the RTO’s large stakeholder community is needed to lend their ideas about what shape the future grid should take.

Goepfrich said the story also applies to load forecasting. An average of many forecasts, she said, will be more helpful than a forecast designed by a few individuals.

“It doesn’t make sense to have a forecast that is divorced from the LSEs’ forecasts,” Goepfrich said. She added that MISO should be more transparent about the “behind the scenes” analyses that might lead it to prefer an independent load forecast over one originated by LSEs.

MISO Director of Planning Jeff Webb said the RTO will evaluate and respond to the load forecast proposal. The RTO committed to soliciting stakeholder opinions on load forecasting after taking a break this summer from ordering more independent load forecasts from Purdue. (See MISO Looks to Members for Load Forecasting Ideas.)

Facing widespread stakeholder disapproval, MISO in June abandoned a proposal to have its 140-plus LSEs annually assemble four distinct 20-year load forecasts with hourly load shapes to align with each of the four futures in the annual MTEP. (See MISO Nixes LSE Load Forecas t Plan.)

September 28, 2018

FERC Upholds PJM TOs’ Supplemental Project Rules

By Rich Heidorn Jr.

FERC on Wednesday rejected a rehearing request over PJM Transmission Owners’ revised processes for planning supplemental projects, ruling it in compliance with Order 890.

The commission denied a request by American Municipal Power, Old Dominion Electric Cooperative and others seeking rehearing of the commission’s Feb. 15, 2018, ruling that the TOs’ processes for developing supplemental projects fell short of Order 890’s transparency and coordination requirements. FERC also approved PJM’s and the TOs’ compliance filing in response to the February ruling (ER17-179, EL16-7 1 -002).

PJM’s Transmission Replacement Processes Senior Task Force meets earlier this year. | *© RTO Insider*

PJM stakeholders have long complained about the rules involving supplemental projects — transmission expansions or enhancements not required for compliance with PJM system reliability, operational performance or economic criteria. TOs can develop, build and seek reimbursement for such projects without the approval of PJM, which only reviews them to ensure they don’t harm reliability.

The Feb. 15 order approved a proposal to move the TOs’ process for planning supplemental projects from the Operating Agreement to Attachment M-3 of the Tariff but required PJM and the TOs to make changes to the attachment and the OA. (See FERC Orders New Rules for Supplemental Tx Proje c ts in PJM.)

The commission said the rehearing request “largely repeats arguments” made earlier in the docket. “We are not persuaded that the commission erred in the February 15 order, which we believe appropriately responds to these concerns.”

AMP, ODEC and others argued the commission erred in permitting Attachment M-3 because it circumvented the division of filing rights in PJM, including the supermajority vote of the Members Committee required for changes to the Operating Agreement. They also said the commission should have required the TOs to respond to stakeholder comments under the supplemental process.

“Order No. 890 requires that stakeholders be afforded the opportunity to provide meaningful input, and that public utility transmission providers ‘craft a process that allows for a reasonable and meaningful opportunity to meet or otherwise interact meaningfully,’” the commission said. “Its requirements are not so prescriptive as to dictate whether and how the PJM Transmission Owners must respond to that input. While we encourage the PJM Transmission Owners to be as responsive as possible to stakeholder comments, we also realize that not all comments may require answer.”

In addition to AMP and ODEC, those seeking rehearing and challenging the March 19 compliance filing were the Delaware Division of the Public Advocate, PJM Industrial Customer Coalition, Illinois Citizens Utility Board, Office of the People’s Counsel for the District of Columbia and Public Power Association of New Jersey, which FERC named the “Load Group.”

“The Load Group’s requests for various additional provisions go beyond what the commission required in, and constitute requests for rehearing of, the February 15 order,” the commission said. “We therefore find these requests to be outside the scope of the compliance proceeding, and were we to consider them as requests for rehearing, would deny them.”