Page 1637 – RTO Insider

June 20, 2016

MISO Planning Subcommittee Briefs

MISO released a work plan last week detailing how it and PJM will use the next six months to improve coordination of generation retirements.

The RTOs’ cooperation on generator retirement studies was one of six directives mandated by MISO, PJM Working to Comply with NIPSCO Order.)

At last week’s Planning Subcommittee meeting, MISO said it and PJM will develop a proposal on retirement studies coordination by July.

MISO said it would work on the issue in meetings of the subcommittee, Planning Advisory Committee, and the RTOs’ Interregional Planning Stakeholder Advisory Committee and Joint and Common Market.

Neil Shah, MISO adviser of seams administration, said the RTOs would be starting from scratch. “The joint operating agreement doesn’t have any retirement coordination language,” he said.

The RTOs differ on retirement rules. MISO requires 26 weeks’ notice prior to retirement, giving it time for a 75-day reliability assessment; PJM requires a 90-day notice and only 30 days of reliability assessment. Further, MISO keeps retirement information confidential unless a reliability concern is identified. PJM has no such confidentially rules and makes retirement information publicly available.

Shah said MISO would submit its work plan to FERC with an informational status filing that is due June 20. Additional status filings are due Aug. 19 and Oct. 18.

He also said MISO plans to share draft JOA language with stakeholders at the RTOs’ Nov. 15 joint and common issues meeting in time to file proposed JOA revisions with FERC by Dec 15.

Pseudo-Ties to Require System Impact Studies; Would be Barred from Sink Switching

MISO wants to conduct system impact studies on all pseudo-tied units with transmission service requests and forbid them from switching sinks until the requests expire.

The RTO is proposing a system impact study be required for all pseudo-tie transmission service requests and that firm point-to-point transmission service be required for the life of the pseudo-tie.

MISO has also proposed that pseudo-tied exports be sourced from a designated generating facility in its commercial model and be modeled in the external balancing authority. Pseudo-tied imports must be sourced from the local balancing authority where the generating unit is physically located and must sink into the MISO local balancing authority where the unit is being pseudo-tied.

“Participants are changing pseudo-ties to another sink after they have a transmission service request,” MISO senior transmission planning engineer Ankit Pahwa said. “It’s a shortcoming in the existing process … and a gray area that has not been covered yet.”

Pahwa said the proposed changes have been coordinated with PJM. He added that participants with existing pseudo-tied transmission service requests would be grandfathered from an impact restudy.

Currently, transmission service requests are evaluated based on an OASIS available flowgate capability evaluation, with only long-term requests — 18 months or longer — requiring a system impact study. Neither long-term nor short-term requests require a source/sink analysis, Pahwa said.

“From MISO’s perspective, we want to be 100% sure that we capture the transmission service impacts if a pseudo-tie moves to a different [local balancing authority],” Pahwa said.

“I think what we’re wrestling here is, does there need to be different treatment for pseudo-ties … much like there are different evaluations for network resource interconnection service for reliability purposes? At the minimum, you need to be sure you have the appropriate type of analysis,” MISO’s Jeff Webb said.

Webb said more conversations with other RTOs were needed before a final proposal. Stakeholders have until July 15 to comment on MISO’s proposal.

MISO Delves into MTEP 16 Studies

MISO is in the midst of developing model scopes for the 2016 Transmission Expansion Plan (MTEP 16), said Dave Ditner of the RTO’s system modeling department. The RTO’s modeling will include a 2017 summer peak with wind contributions of 15.6% and 2021 modeling of summer peak, summer shoulder and light load scenarios with wind contributions ranging from 15.6 to 90%.

William Kenney, an expansion planning engineer for MISO’s Southern Region, also presented the finalized MTEP 16 voltage study scope. The study will use nine 2021 power flow models, including summer, winter and a shoulder with wind at 40%. MISO will release the final MTEP 16 voltage stability study in October.

Additionally, seven transfers will be studied in model year 2021 under the MTEP 16 transfer analysis scope:

MISO North to SPP;
Two different paths from Manitoba Hydro to MISO North;
PJM in Northern Illinois to PJM Ohio;
Missouri and Illinois to PJM Ohio;
SPP to Southern Co.’s territory; and
MISO South to SPP.

MISO will finalize the transfer analysis in mid-August.

Storage May Be Removed from Non-Transmission Alternatives

MISO presented stakeholders with draft language on Business Practices Manual 020, continuing a nearly yearlong discussion on non-transmission alternatives.

The RTO is suggesting separating energy storage devices that could solve a transmission issue from BPM language on non-transmission alternatives. MISO is also recommending discussion on whether storage can serve as a non-traditional transmission alternative move to the Planning Advisory Committee, MISO’s Matt Tackett said.

In April, MISO proposed classifying storage as a non-traditional transmission alternative. (See “Energy Storage Prompts 2nd Transmission Alternative Category,” MISO Planning Subcommittee Briefs.)

Indianapolis Power & Light’s Lin Franks said storage provides frequency control and voltage control much like transmission.

MISO will present a second draft of the BPM language at the August Planning Subcommittee meeting.

— Amanda Durish Cook

June 20, 2016

ERCOT Board of Directors Briefs

The ERCOT Board of Directors approved extending a reliability-must-run contract with NRG Energy for its Greens Bayou Unit 5 plant in the Houston area. The RMR, ERCOT’s first in five years, will run through June 30, 2018, at which time additional generation and transmission infrastructure is expected to be in service.

The 371-MW natural gas-fired generator was originally scheduled to be mothballed June 27, but ERCOT’s RMR contract June 3 made the unit available to the market through September. (See ERCOT to Keep NRG’s Greens Bayou Plant Running for Summer.)

Staff analysis indicates Greens Bayou Unit 5 is needed to maintain or support reliability in the region over the short term.

“Having that unit available will reduce the likelihood of having to engage a constraint-management plan, which would likely mean load shed,” said Warren Lasher, ERCOT’s director of system planning.

Under the RMR agreement’s terms, ERCOT will make a standby payment to NRG of $3,185/hour during on-peak hours, whether or not the unit runs.

Directors Carolyn Shellman, of CPS Energy, and Read Comstock, of Direct Energy, both encouraged additional discussion on the ISO’s RMR practices at the next board meeting. “I think we should encourage a holistic review of the RMR protocols,” Comstock said.

Lasher said staff will begin evaluating must-run alternatives, which it will bring to the board in August. The Technical Advisory Committee is also creating a task force to focus on the issue.

“I would like to see the market solve these situations, so we don’t have to,” Director Judy Walsh said.

Staff said the region’s reliability concerns will subside before the summer peak of 2018, when the $590 million Houston Import transmission project — “the ultimate [RMR] exit strategy,” Lasher called it — is expected to be completed. New generation is also on the way, with NRG’s 390-MW PH Robinson peaking facility expected to come online later this summer and Exelon’s 1,148-MW Colorado Bend combined cycle plant to follow in July 2017.

ERCOT also added 75 MW of power last week when NRG converted a gas turbine at its Houston-area W.A. Parish facility into a cogeneration unit. The unit was originally built to produce steam and electricity as part of the Petra Nova post-carbon capture and sequestration joint venture with JX Nippon Oil & Gas Exploration. The unit went into mothballs May 19 during its conversion process.

Magness: Mild Weather Cuts into Admin Revenue

CEO Bill Magness said ERCOT’s year-to-date revenues are $2.3 million over budget, despite a $2.2 million shortfall in the administrative fee that is attributed primarily to mild weather this year. He said the ISO is on track to finish $3.1 million above budget, thanks to positive variances in resource management, hardware and software, and employee benefit costs.

“It looks like we can create a favorable variance, but we don’t know what the weather’s going to be like,” Magness said.

ERCOT’s senior meteorologist, Chris Coleman, said this summer will “likely” not be as warm as last summer — the 17th hottest in Texas over the past 121 summers — or 2011, when sustained heat led to several peak-demand records and seven emergency alert notifications.

“This summer is one of the more difficult forecasts I’ve put together,” Coleman said. “Most indicators suggest a milder summer. I can guarantee you we will not see a repeat of 2011.”

Coleman said ocean temperatures, the primary influence on weather patterns, have been above normal in both the Pacific and Atlantic Oceans. He also said the transition from the second-strongest El Niño on record to what he expects to be a neutral or weak La Niña could lead to above-normal temperatures in the late summer.

The meteorologist said he does see “more potential for hurricane activity in the Gulf of Mexico” than his first four years with ERCOT. Coleman predicted five hurricanes, of which one or two could be in the Gulf, and the potential for two storms to make landfall in Texas.

“It doesn’t mean Texas will be hit by a tropical storm or hurricane,” he said, “but if there are three to five in the Gulf, the potential is greater.”

Dan Woodfin, ERCOT’s director of system planning, said it would take “really, really extreme” weather conditions to affect the grid’s operations. The ISO said last month it has more than enough natural gas and renewable energy capacity to meet its projected summer peak this year. (See ERCOT Briefs: Ample Capacity; Outage Procedures.)

“We’re not expecting a 2011 summer,” Woodfin said. “We have procedures in place should something out of the ordinary happen.”

The Rio Grande Valley, long a trouble spot for congestion, “looks better this summer than it has in quite a few years,” Woodfin said. He said a 345-kV line was completed last month and a cross-valley project went into service two weeks ago, easing some concerns.

LP&L Integration Could Unlock More Panhandle Wind Energy

Lasher shared staff’s report on how to integrate Lubbock Power & Light into ERCOT, which recommends a plan that would allow for further export of the Texas Panhandle’s ample wind energy supplies.

Lasher said staff’s “option 40W” will cost $364 million and result in 141 miles of new 345-kV rights of way, but it could also help export 4,246 MW of wind energy elsewhere on the grid.

“It’s not the low-cost option,” he said, “but it’s preferred specifically because it’s consistent with the longer-term needs ERCOT has identified for the region.”

LP&L announced last September it planned to disconnect from SPP and join ERCOT by 2019. Xcel Energy, whose Southwestern Public Service subsidiary serves LP&L’s load, asked FERC in May for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan. (See Xcel Asks for $88.7M Fee for Lubbock Switch to ERCOT.)

Staff combined studies supplied by LP&L and Sharyland Utilities, which has transmission assets in the Panhandle, and folded them into its own analysis. The final report will be filed in the Public Utility Commission of Texas’ LP&L docket (# 45633).

Changes to Calculation of Market’s Physical Responsive Capability

ERCOT’s methodology for determining ancillary service requirements will change July 1 when it adjusts the reserve discount factor (RDF) in the market’s physical responsive capability (PRC) calculation on quick-response online generation.

The board unanimously approved staff’s recommendation on the adjustment, pleasing PUC Commissioner Ken Anderson, who has raised concerns over an event last August when the ISO’s scarcity pricing adder, the operating reserve demand curve (ORDC), did not appropriately reflect a reduction in the PRC.

“In defense of ERCOT, these changes are looking to solve the problem we saw last August … the disconnect between the ORDC and PRC,” he said.

On Aug. 13, operators deployed non-spinning reserve service as the PRC dropped to 2,371 MW. However, ERCOT’s real-time online reserve capacity was 3,629 MW, which was reflected in wholesale prices.

ERCOT buys responsive reserve service to ensure sufficient PRC is available. The measure approved by the board aligns the ISO’s systemwide discount factor, lowering it from 2% last year to 1%. It also makes operational adjustments to the RDF.

Board Approves 13 Revision Requests

The board pulled one nodal protocol revision request (NPRR) from the consent agenda but gave it its unanimous approval following a brief discussion.

NPRR758 is designed to provide improved transparency to market participants when transmission outages that could create congestion are submitted with less than 90 days’ notice. It would identify outages that have historically resulted in high congestion costs, as adjusted through stakeholder review to account for upgrades and other changes.

“I’m concerned we don’t have a clear-cut requirement to how we came up with the list and published it,” said Nick Fehrenbach, manager of regulatory affairs and utility franchising for the City of Dallas, before offering up the motion for approval. “We need clear requirements and how we can change them, or we’re leaving ourselves in a quandary.”

TAC Chair Randa Stephenson, of the Lower Colorado River Authority, said the subcommittee and ERCOT staff will “work to ensure a list of high-impact outages is available to public knowledge.”

The board’s consent agenda resulted in the approval of nine more NPRRs, two system change requests (SCRs) and a nodal operating guide revision request (NOGRR).

NPRR709: Modifies the alternative-dispute resolution procedure and clarifies parts of the settlement and billing dispute process.
NPRR752: Clarifies revision request protocol language to reflect current ERCOT practices.
NPRR754: Revises the posting frequency of the load-forecast distribution factors report. Posting is required only when the factors are changed.
NPRR761: Clarifies that a resource will not be eligible for make-whole payment startup-cost compensation in the day-ahead market when the market considers the resource as not having a startup cost.
NPRR762: Removes references to the provision of responsive reserves across the DC ties.
NPRR763: Corrects the formula for calculating qualified scheduling entities’ monthly block load transfer amount to reflect a charge, rather than a payment.
NPRR764: Changes calculations for charges to entities short their capacity obligations in reliability unit commitment. Calculations for wind and solar resources will be based on their production potential.
NPRR765: Eliminates publisher names for various fuel price indexes and provides additional clarifying language regarding the use of a substitute source for daily fuel prices.
NPRR766: Aligns the description of the systemwide discount factor with the proposed operational adjustment to the RDF in the physical responsive capability calculation; also aligns the posting for RDFs applicable to both generation and load resources.
SCR788: Updates the formula used to calculate the “generation to be dispatched” (GTBD) value and help minimize GTBD oscillations from one security-constrained economic dispatch interval to the next.
SCR790: Adds an additional level of geographical granularity — the Panhandle/North area — to reports on wind power production and forecasts.
NOGRR050: Removes ERCOT’s requirement to produce outage-scheduling reports until systems can be changed to include only transmission service providers’ outages.

– Tom Kleckner

June 20, 2016

FERC Clarifies Electronic Quarterly Report Rules

FERC last week clarified its Electric Quarterly Report (EQR) reporting requirements, emphasizing that transmission providers must report transmission-related data (RM01-8, et al.).

The order also updates the EQR Data Dictionary, effective with the report for the fourth quarter of 2016, clarifying reporting requirements and fields related to “Increment Name” and “Commencement Date of Contract Terms.” It also makes changes regarding the “Time Zone” field options and deletes fields for reporting e-Tag data.

Future minor or non-material changes to EQR reporting requirements and the Data Dictionary will be posted directly to the commission’s website, and EQR users will be alerted via email of the changes.

– Rich Heidorn Jr.

June 20, 2016

PJM News Briefs from FERC Open Meeting

FERC last week denied a request by PJM’s Independent Market Monitor to clarify or rehear a March order in which the commission found fault with the RTO’s use of the cost-based energy offer cap as the sole measure of short-run marginal cost in calculating capacity market caps (EL14-94, ER16-1291).

At the same time, it accepted PJM’s compliance filing in response to the March ruling. (See FERC Rejects PJM’s Method for Capacity Offer Caps.)

In its request, Monitoring Analytics generally supported FERC’s order but called flawed the use of market-based offers as the measure of short-run marginal costs when they are higher than cost-based offers.

“The Market Monitor contends that the extent to which a market-based offer exceeds a cost-based offer constitutes a markup, and markup is not part of a competitive offer,” the commission said.

“We continue to find that, with limited exceptions, PJM should use, for the purpose of calculating a unit-specific capacity market offer cap, a resource’s non-zero market-based offer to reflect its marginal costs,” FERC ruled. “Simply because a market-based offer exceeds a cost-based offer does not necessarily establish that the market-based offer fails to reflect a resource’s marginal costs.”

The March ruling stemmed from a 2014 FirstEnergy petition that said PJM’s Market Monitor was violating the Tariff by calculating marginal costs using the lower of the market-based offer and cost-based offer.

FERC Denies Rehearing on Order Requiring DR in Capacity Auctions

FERC denied Talen Energy’s request for rehearing of a July 22 order that required PJM to include demand response in its transition auctions for Capacity Performance (ER15-623, EL15-80).

FERC, PJM — Smart Meter *Source: CPS Energy*

That ruling caused the RTO to delay the transition auctions. (See FERC Orders PJM to Include DR, EE in Transition Auctions.)

The commission also accepted a compliance filing by PJM in response to the July 22 order.

Talen had sought to apply a ruling by the D.C. Circuit Court of Appeals that voided FERC’s jurisdiction over DR in energy markets. However, the Supreme Court later reversed that ruling. (See Supreme Court Upholds FERC Jurisdiction over DR.)

“Accordingly, we dismiss Talen’s rehearing request as moot,” FERC said.

FERC also dismissed an objection by the Advanced Energy Management Alliance Coalition regarding the method PJM proposed to measure and verify DR participation in the transition auctions, saying it was an unrelated issue.

Commissioner Tony Clark concurred in a separate statement.

“I write separately to note my policy and procedural disagreements with the underlying order as fully explained in my separate statement of July 22, 2015,” he said.

Clark dissented from that order, saying it was improper procedurally because the commission had previously approved “unambiguous” Tariff language barring DR and energy efficiency from the auctions.

— Suzanne Herel

June 20, 2016

CAISO to Study Impact of Gas Shortages on Reliability

By Robert Mullin

CAISO transmission planning staff last week proposed studies on the implications of gas shortages on grid reliability.

The planners outlined the studies in a June 13 stakeholder call, saying they will consider the risks to Northern California as well as the more vulnerable southern part of the state.

The disparity between the regions stems from design differences in their pipeline systems and the synergy between Southern California’s storage facilities and its pipeline network.

“Gas storage in the [Los Angeles] Basin is critical [to pipeline operations],” said ISO senior advisor David Le, referring to the gas system’s dependence on the Aliso Canyon storage facility.

Le pointed out that the Aliso Canyon — closed earlier this year because of a gas leak — is vital not only for its massive 86 Bcf storage capacity, but also for its ability to quickly supply large volumes of gas to support pipeline pressure.

Aliso Canyon usually accounts for more than 65% of the inventory held in Southern California’s four major storage sites. The facility also boasts a daily withdrawal capacity of 1.86 Bcf, which helps keep 17 gas-fired generators in the basin supplied with gas under strained conditions.

That withdrawal capability is usually tapped during summer months to help generators meet peak demand. CAISO says that, because of the “magnitude and speed” of the generators’ consumption, pipeline capacity is often insufficient to supply their needs without the ability to backfill from storage such as Aliso Canyon.

CAISO plans to model multiple scenarios stemming from the closure of Aliso Canyon to assess the potential long-term impact of the gas system’s balancing act on Southern California’s grid reliability. Planning staff will develop scenarios in which gas pipeline operators and gas generators lose access to other storage facilities in the region in addition to Aliso.

The study is intended to take a long view, looking at the implications of such gas curtailments to inform transmission planning for 2021 and 2026 as California advances on its 50% renewables mandate.

A parallel study would examine the likelihood for gas curtailments in Northern California, a region with a “much different” gas system, according to Binaya Shrestha, CAISO regional transmission engineer lead.

To provide context for his assertion, Shrestha pointed to the February 2011 gas outages that cut supplies to a number of San Diego-area generators. “Southern California is [subject to] historical outages, but in Northern California, there hasn’t been any curtailment of that level for gas-fired plants,” he said.

That success can be attributed in part to both the line capacity and topology of the gas system.

caiso, gas shortages, reliability — The proximity of gas storage facilities to Northern California’s backbone pipeline provides flexibility for the region’s gas system.

The region’s backbone pipeline — Line 401/402 — has a firm capacity of more than 2 Bcfd. Additional supply arrives via the Mojave gas system originating in the southern part of the state, which serves about 2,200 MW of generation in the ISO’s Pacific Gas and Electric zone.

Furthermore, nearly all of Northern California’s eight major gas storage facilities are distributed along the length of Line 401/402. That arrangement provides operational flexibility because gas can be injected into the system from multiple sites.

Those facilities also equip the region’s gas suppliers with a combined 238 Bcf in inventory capacity — double that in Southern California — and more than 4.5 Bcf in withdrawal capacity.

Still, the ISO wants to better understand the dynamics of gas supply in Northern California to investigate what chain of events leading to curtailments could compromise the region’s electric reliability.

Stakeholders must submit comments about the gas-electric studies by June 27. Findings will be incorporated into the ISO’s draft transmission plan early next year.

June 20, 2016April 2, 2025

FERC Issues 1st RTO Price Formation Reforms

By Michael Brooks

WASHINGTON — RTOs will be required to align their settlement and dispatch intervals and implement shortage pricing during any shortage period under new price formation rules approved last week by FERC (RM15-24).

FERC Order 825 requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. Although all RTOs currently dispatch resources in five-minute intervals, ISO-NE, MISO and PJM settle those transactions based on the average price for all dispatch intervals during the hour.

This misalignment distorts price signals, as compensation is based on average hourly prices rather than specific periods, including those of greatest need. “These distorted price signals can mute a resource’s financial reward for being able to quickly respond to system needs and create a disincentive for resources to respond to price signals,” Stanley Wolf, of FERC’s Office of Energy Policy and Innovation, said at the commission’s open meeting Thursday.

Additionally, in some RTOs, an energy or reserve shortage is required to last a minimum amount of time before shortage pricing is triggered. “Due to such delays, short-term prices fail to reflect potential reliability costs, as well as fail to reflect the value of both internal and external market resources responding to a dispatch signal,” Wolf said.

Commissioner Colette Honorable called the order — the first final rule in the commission’s efforts to reform price formation in the organized electricity markets — a “milestone.” The commission began evaluating price formation in 2014 and issued a Notice of Proposed Rulemaking in September. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)

“These requirements will help ensure that rates for energy and operating reserves are just and reasonable and will align prices with resource dispatch instructions and operating needs, provide appropriate incentives for resource performance and maintain reliability,” FERC said.

The final order clarifies that the rules would apply to all supply resources, including demand response.

The new requirements take effect 75 days after publication in the Federal Register. Each RTO will be required to make a compliance filing 120 days after that detailing the tariff changes needed to implement the new rules. The order stipulates that FERC will allow an additional year after the compliance filing deadline for the settlement interval changes to go into effect, while it will allow another 120 days for the shortage pricing changes.

“I know that it will take some time and effort for the RTOs to comply with the portion of the rule on settlement intervals; it won’t necessarily be easy,” Commissioner Cheryl LaFleur said. “However, I think it’s critically important that markets send clear, accurate, timely and undiluted price signals.”

June 20, 2016

House Panel OKs Bill Targeting Clean Line Project

By Tom Kleckner

A U.S. House of Representatives committee last week approved legislation that aims to stop Clean Line Energy Partners’ plans to build a 700-mile HVDC transmission through Oklahoma and Arkansas.

AR Rep Steve Womack (Steve Womack) - congress clean line project — Womack

The House Committee on Natural Resources advanced the Assuring Private Property Rights Over Vast Access to Land (APPROVAL) Act by a 19-11 vote June 15. The bill is sponsored by Rep. Steve Womack, one of the members of an all-Republican Arkansas congressional delegation that is united in opposition to the Clean Line project.

The bill would amend the Energy Policy Act of 2005 to prohibit the secretary of energy and federal power agencies from using eminent domain for transmission rights of way without first receiving approval from a state’s governor and regulatory body. It also restricts the transmission line’s siting to existing federal right of way or land managed by federal entities.

Womack said the bill is “another positive step toward passage in a long and hard-fought battle to allow states to retain the historic precedent of authority for interstate transmission projects.”

“It is our firm belief that the [Energy Department] has overstepped its bounds, and reversing this decision through the passage of the APPROVAL Act remains a top priority,” Womack said, speaking for the rest of his state’s delegation.

Houston-based Clean Line issued an opposing statement, saying that if the bill became law, “it would kill jobs by creating significant barriers to the many businesses in Arkansas … that build American infrastructure, as well as raise electric power costs.”

“Denying American consumers access to the lowest-cost clean energy resources is never good policy,” added Clean Line, which noted more than $100 million in private funds have been invested in the project.

Clean Line’s Plains & Eastern Clean Line is a $2.5 billion, privately funded project that is supposed to deliver 4,000 MW of wind power from the Oklahoma Panhandle through Arkansas to the Mississippi River. The line would interconnect with the Tennessee Valley Authority near Memphis, after first dropping off 500 MW at a converter station in central Arkansas.

congress, clean line project — Clean Line Project Map *Source: Clean Line Energy Partners*

Clean Line proposed the project in response to the Energy Department’s 2010 request for proposals for transmission projects under Section 1222 of EPACT 2005, which authorizes the department to participate in “designing, developing, constructing, operating, maintaining or owning” new transmission.

The department approved the project in March, saying it would participate through the Southwestern Power Administration, a federal agency that markets hydroelectric power from 24 dams in six states. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)

The Arkansas Sierra Club said it opposes Womack’s bill.

“The Clean Line project has been in the works since 2010 and has undergone a very thorough and expensive public permitting process in accordance with federal law,” said the Sierra Club’s Arkansas director, Glen Hooks. “Rep. Womack’s bill seeks to change that law after the permitting process has been underway for years. That’s not only bad for our state’s air and economy, it’s blatantly unfair to the company.”

Arkansas Sen. John Boozman has filed a matching bill that is co-sponsored by the state’s junior senator, Tom Cotton. The Senate Committee on Energy and Natural Resources held a hearing on the bill in May but has taken no action on it since then.

“Arkansans should be heard in discussions that impact their lands,” Boozman said in a statement released by his office. “Our bill restores the role of states, which in the past had the freedom to approve or reject electric transmission projects. These decisions should not be made behind the closed doors of a federal agency in Washington, D.C.”

June 20, 2016

CAISO News Briefs from FERC Open Meeting

FERC last week granted PacifiCorp’s request to suspend the relicensing proceeding for the 169-MW Klamath Hydroelectric Project in order to give the utility more time to transfer the facility to new owners ahead of the removal of four dams (Project No. 2082-027).

The fate of the project — which straddles the California-Oregon border along the Klamath River — became the subject of negotiations among state and federal agencies, Native American tribes, environmental groups and local farmers in 2008. Two years later, PacifiCorp reached a settlement agreement to remove four of the project’s dams, contingent on passage of federal legislation authorizing the removal.

Congressional inaction triggered dispute resolution proceedings early this year, resulting in PacifiCorp agreeing to transfer the project’s license to a new entity — the Klamath River Renewal Corp. — in July. That entity is expected to immediately file with FERC to surrender and remove the dams under the commission’s process, rather than await approval from Congress.

“Requiring the parties, other stakeholders and commission staff to simultaneously proceed with both a relicensing proceeding and a transfer and surrender proceeding would be burdensome and an inefficient use of resources,” the commission said in its ruling.

Irongate Dam on Klamath River (American Rivers) — The Irongate Dam is one of four scheduled to be removed from the Klamath River. *Source: American Rivers*

FERC OKs NextEra Tariff Revisions Covering CAISO Competitive Projects

FERC last week accepted a NextEra Energy compliance filing revising a tariff for two transmission projects the company has been awarded through CAISO’s competitive selection process (ER15-2239-002).

The commission agreed with NextEra’s explanation that the tariff’s formula rate would only apply a 150-basis-point adder to an initial assessment of the long-term cost of debt for the projects — a figure based on the company’s debt cost for a Texas project. The adder, the company clarified, would be recalculated once long-term debt is actually issued.

The commission also rejected a request by the California State Water Project that NextEra’s tariff clarify the term “third-party debt,” ruling that the argument was outside the scope of the proceeding.

“The commission has repeatedly held that compliance filings are limited to the specific directives of the commission’s order,” the commission wrote. “The sole issue on review is whether the filing party has complied with those directives.”

– Robert Mullin

June 20, 2016April 2, 2025

Lack of Carbon Pricing Distorting RTO Markets, CEOs, Ex-Regulator Say

By Rich Heidorn Jr.

NEW YORK — Organized markets are being distorted because of policymakers’ failure to price carbon, two grid operator CEOs and a former FERC and state commissioner told a New York Energy Week audience last week.

“I would say that in my … 16 years, this is the most vulnerable that I’ve seen the market construct yet,” ISO-NE CEO Gordon van Welie told more than 75 industry participants at Goldman Sachs’ office in lower Manhattan.

Van Welie appeared on a panel with NYISO CEO Brad Jones and former FERC and Pennsylvania Public Utility Commissioner Nora Brownell, who both joined van Welie in lamenting that CO₂ emissions remain a market externality. The conference was created in 2013 by EnerKnol, an energy policy research and data company.

Left to right: Moderator Rich Heidorn Jr., RTO Insider; Gordon van Welie, ISO-NE; Brad Jones, NYISO; former FERC Commissioner Nora Mead Brownell Copyright: New York Energy Week

“We value what nuclear brings to the table” as a baseload, low-carbon resource, Jones said. “But our markets don’t.”

Asked about Gov. Andrew Cuomo’s proposed zero emission credits for upstate New York nuclear units, Jones said, “We’d like to see that be temporary in nature … a bridge into a future where the market can really resolve these issues.”

Obvious Solution

Brownell was blunt.

“We don’t have the leadership to deal with the obvious solution, which is a carbon tax. It’s straightforward, it’s transparent, it sends the right market signals,” said Brownell, who served on FERC from 2001 to 2006. “The market signals are there; we’re not allowing them to really work. And the more we create these constructs, the more we ultimately distort markets.”

Van Welie said the lack of carbon pricing is putting the public policy of achieving reliability through wholesale markets in conflict with that for reducing carbon emissions.

Allowing resources with “out-of-market” contracts under state clean energy procurements to offer into the capacity market will distort price formation, said van Welie. “And that really creates a problem in terms of ensuring reliability, but it also creates a problem with regard to the long-term incentive in the market as well.”

‘Fundamental Questions’

Brownell said the conflict raises “fundamental questions.”

“Do we really value markets, and have we done a sufficient job of illustrating the economic benefits of markets?

“Secondly, what is the role of the RTO? We have piled on … to what was originally a pretty straightforward economic dispatch reliability model. I’m not saying they are incapable of doing this; I just wonder if they are the best entity to do it. Or we are burdening them to the point where they really can’t do their fundamental job well, which is ultimately and critically important to both economic development and the environment in which we live.”

Building Infrastructure

Jones and van Welie also shared their challenges in building the electric and gas infrastructure needed to meet reliability and environmental goals.

Jones noted that it has historically taken 10 to 12 years to get new transmission approved, sited and constructed in New York.

Based on that, he said, the ISO “would have two years remaining in our 14 years to interconnect everything into the system to meet the [2030 state goal of 50% renewables]. That is not possible. We have to improve our ability to move these projects through the system.

“Given that we have a single siting authority, it does give us the advantage to begin to streamline that process,” he added.

For the six-state ISO-NE, siting issues are compounded by cost allocation disagreements.

Unlike the “singular objective” that made the region’s $12 billion transmission buildout for reliability possible, there is less consensus on transmission to deliver renewables, said van Welie.

Part of the problem is that some renewable developers are trying to connect in weak parts of the region’s grid. “Up in Maine, we have 3,000 MW of wind projects trying to interconnect to a transmission system designed to serve 300 MW of load,” van Welie said.

“We’ve spoken to the developers and said, ‘Why don’t we do a cluster study and why don’t you guys sort of get together and pool your money and all share in this investment that’s required and we can get you all connected?’ They don’t want to do that.

“And then we turn around to the states and say, ‘There’s a bunch of wind developers up here in Maine, some of which have actually signed contracts with you,’ he continued. “‘Can’t we get you guys to pay for some transmission to integrate them?’ And we can’t get that to happen either. And so we’re stuck, quite honestly.”

Van Welie said he has some hope that state clean energy solicitations will break the log jam.

“Maybe they’ll choose one that’s up in Maine and we’ll actually resolve this problem,” he said. “If they don’t, I think we’re going to remain stuck.”

Cost Allocation

Complicating New England’s transmission challenge is the Order 1000 cost allocation methodology approved by FERC. “The northern states don’t agree with the cost allocation and they’re the ones that would have to site these transmission projects,” van Welie said. “Ultimately I think we’re going to do something like what Texas did” with its Competitive Renewable Energy Zones (CREZ), he said.

Jones, who worked for ERCOT and Luminant before joining NYISO last year, said he sees lessons in how Texas and California — other single-state ISOs — were able to build renewables.

“In order to meet this aggressive goal, we have to begin identifying in advance where we think some of these renewables will locate. And then by that identification we can begin to build out a collector system, which allows those renewables to feed into the market,” he said. “We have to begin to remove some of that risk that is … on the developers by building out transmission to locations where we think there’s a high probability for those developers to come.”

Gas-Electric

For New England, the challenge of upgrading the transmission grid is compounded by its stressed natural gas infrastructure. This is a concern, van Welie said, because gas will be needed to balance renewables for the next “several decades,” until storage becomes more affordable.

“One of the most vexing problems we have is this disconnect between how the gas industry is regulated and the electric industry is regulated,” he said. “I think we all launched into wholesale markets 15 years ago thinking that the markets would do a great job of optimizing existing infrastructure, and of course they’ve done that. But we have now pushed the gas system to the limit.”

“So there’s nobody looking out to say, ‘How do we plan the gas system to be able to make efficient fuel delivery to the electric system?’ When we’ve approached the FERC on this issue, basically they’re boxed in because of the Federal Power Act.”

Brownell echoed van Welie’s concern, urging “integrated planning.”

“We need to look at the entire infrastructure needed. Texas [CREZ] worked. It just totally worked. … We just cannot continue to do things state by state, silo by silo, policy by policy,” she said.

Distributed Generation, New York REV

The panelists also gave their views on distributed generation, New York’s Reforming the Energy Vision initiative and its proposed rewrite of the utility revenue model.

“The debate about the big or the small grid [being] either/or is not really a debate that I buy into,” Jones said. “It really has to be both. We can’t … have a large renewable program and then trust that all that will be developed in rooftops. … To get the efficiencies out of building renewables in a way that just doesn’t cost too much for all of our customers, we need to do that in large scale. And so a lot of that large-scale [generation] will be a distance away from our [load] so it really has to be a combination of both the big grid and the small grid.”

Former FERC & PA PUC Commissioner Nora Brownell Copyright: New York Energy Week

Brownell, who served on the Pennsylvania commission (1997-2001) when it eliminated utilities’ monopolies and adopted customer choice, and now serves on the board of National Grid, was asked her reaction to the New York Public Service Commission’s May order seeking to change the utility revenue model.

Instead of earning returns on investments in large, centralized power systems, utilities would have “earnings opportunities” based on their performance as a “platform” enabling distributed resources and other new technologies. (See NY REV Order Revamps Utility Business Model.)

“Utilities cannot deny that the business model is changing with them or without them,” she said. “So I think there is real leadership among some — not all — to be part of that solution.

“The challenge is that if you’re going to have performance metrics — and we’ve seen them in the U.K.; they’ve worked for years — they need to be clear, they need to be measurable. You can’t have what you had in the telecom industry, which was: ‘We’ll give you extra money for doing the following 10 things, but we’re not going to really measure whether you’ve done them.’”

June 20, 2016

Kormos, Former PJM Exec, Signs on with Exelon

Mike Kormos, who abruptly resigned in March from his post as PJM executive vice president and chief operations officer, began a job last week as Exelon’s president of wholesale markets and energy policy.

Mike Kormos, PJM - exelon — Kormos *copyright RTO Insider*

“Mike brings extensive knowledge of the wholesale electricity markets,” said Joe Dominguez, executive vice president of governmental and regulatory affairs and public policy. “His expertise in market innovation and design … will strengthen Exelon’s policy efforts as we continue to advocate for market reforms that will benefit our customers, our communities and our companies.” (See Exelon to Close Quad Cities, Clinton Nuclear Plants.)

Kormos was with PJM for 27 years, and last year he sought to replace retiring CEO Terry Boston. The post went to Andy Ott, who long had been Kormos’ equal on the organizational chart. (See Kormos Marks Quarter Century Mark at PJM.)

At the time of Kormos’ resignation, Ott said his position would not be filled. Ott this month announced organizational changes, assigning Kormos’ duties overseeing the Operations Division to Senior Vice President Stu Bresler. (See Ott Restructures PJM Divisions, Leadership.)

In his new role, Kormos will be in charge of formulating and furthering Exelon’s positions on energy and transmission bulk system policy planning, developing effective wholesale energy markets, overseeing the company’s participation in NERC initiatives and monitoring grid reliability issues, including cybersecurity, the company said.

Kormos, who will report to Dominguez, has served on several boards, including the Eastern Interconnection Planning Collaborative, Reliability First Corp. and Eastern Interconnect Data Sharing Network.

He holds a bachelor’s degree in electrical engineering from Drexel University and earned an MBA from Villanova University.

— Suzanne Herel