Electric system disturbances resulting from the loss of generation or transmission in the U.S portion of the Western Interconnection increased by 50% between 2015 and 2016, according to a new report from the Western Electricity Coordinating Council.
There were 24 “loss of generation or transmission” events in 2016 compared with 16 in 2015, WECC said in its State of the Interconnection report. The category refers to the loss of three or more Bulk Electric System facilities from a common cause, or the loss of 2,000 MW or more of generation.
WECC did not provide detail on the reason for the increase and did not immediately respond to a request for more information.
Loss-of-load events in the interconnection also increased between 2015 and 2016, from one event to five. These events are defined as loss of firm load for 15 minutes or more exceeding 300 MW for entities with demand of 3,000 MW or greater in the previous year, or exceeding 200 MW for all other entities. There were three loss-of-load events in 2014.
The largest loss of load occurred Aug. 7, with the loss of 665 MW, about 0.5% of the day’s peak system demand of about 127,000 MW.
Not all bulk power system disturbances qualify as loss-of-load events, and “relatively few meet the criteria,” WECC said.
| WECC
Noting the increase, WECC said that “more years of data will be necessary to determine whether this signifies an increasing trend and potential concern, a statistical anomaly or normal variation between years.”
“Loss of monitoring or control” events — those lasting 30 minutes or more that affect an entity’s ability to make operational decisions — also increased in the Western Interconnection last year. There were 20 such events in 2015 and 22 in 2016.
Islanding events — unintentional system separation resulting in an electrical island of 100 MW or more — dropped from eight in 2015 to just one in 2016.
Incidents in which a remedial action scheme failed or was enacted unnecessarily dropped from four in 2014 to three in 2015 and 2016.
The Western Interconnection housed a combined nameplate generation capacity of 267,000 MW in 2016, up 1% from the previous year. Natural gas-fired generation represented the largest share (40%), followed by hydroelectric (27%), coal (14%) and wind (8%), with the balance coming from solar, geothermal, nuclear and “other” utility-scale generation.
| WECC
In 2016, “retirement of coal and steam turbine gas units led to slight decreases in capacity from these fuel types, while the installed capacity of utility-scale solar increased by over 6,000 MW,” WECC said. There is about 14,350 MW of solar in the interconnection, or about 5% of capacity.
Hydro dominates in the Northwest, while California and the Southwest are heavy with natural gas. Solar capacity is growing in California, and wind capacity is increasing in the Rocky Mountains and along the Columbia River.
WECC is the regional entity responsible for compliance monitoring and enforcement in the Western Interconnection, which spreads west from the Rocky Mountains to California, north into western Canada and south to Mexico’s Baja California Peninsula. It consists of 37 balancing authorities and is one of four major interconnections across North America. The WECC report covers the bulk power system, which does not include local electric distribution systems.
The WECC Board of Directors is due to receive an update regarding the State of the Interconnection report at its June 21 meeting in Salt Lake City.
Paul Muncy, of MISO’s transmission access planning division, told the Planning Advisory Committee last week that BPM 015 mirrors the RTO’s queue filing and is nearly complete, with final review expected over the next few weeks. Language was crafted by the Interconnection Process Task Force (IPTF), which was due to sunset in July but will now continue through December after a unanimous sector vote to extend the group’s existence by six months.
Muncy also said MISO will create a separate process for a few HVDC projects currently in the queue’s system planning and analysis phase. The RTO has already filed to immediately move those projects out of the queue and put them in a holding pattern (ER17-1793). Muncy said a filing on the new process will be ready by the end of this year.
The Merchant HVDC Task Team will work on the separate HVDC filing, stakeholder sectors decided in a vote at the meeting. Muncy said the team began work on Tariff language, but the RTO prefers to transfer that job to the IPTF, which makes recommendations involving interconnection queue revisions. During a sector vote at the PAC meeting, the Coordinating, Transmission Owners and Environmental sectors voted to keep the assignment in the task team, with only the Transmission-Dependent Utilities sector voting in favor of an IPTF handoff. The State Regulatory, Power Marketers and End Users sectors abstained from voting.
MISO Moves Toward Singular Attachment Y Status
MISO plans by the end of the year to introduce Tariff changes eliminating resource suspensions in favor of a single retirement process that would allow a potentially retiring resource to retain the ability to participate in an upcoming capacity auction.
The RTO proposes to reduce its Attachment Y process to a catch-all “economic shutdown” status that no longer recognizes temporary suspensions or require resource owners to provide return dates. Owners could reverse a retirement decision over a full planning year and participate in an upcoming Planning Resource Auction. The same yearlong rescission period will apply to system support resources whose status has been lifted by MISO. (See “Removal of Temporary Suspensions will Provide Generators Flexibility, RTO says,” MISO Planning Advisory Committee Briefs.)
“We don’t need to have a separate process for handling suspensions,” MISO adviser Joe Reddoch said.
MISO will add a provision allowing it to terminate interconnection service for units that have been on extended outage for more than 36 months, he said. “This allows us to dispose of models in our planning studies that are inoperable but show up as available. This way we get rid of the hoarding of interconnection service.”
An additional provision would permit an asset owner to waive its right to rescind a retirement decision and progress directly to retirement. Reddoch said some resource owners might be ready to make a binding decision by the time they file an Attachment Y request.
Reddoch said the proposal’s largest point of contention is the removal of confidentiality for results of Attachment Y reliability studies. By the time confidentiality is lifted, generator owners would on average be three months away from retirement and would have likely made a public announcement, he said.
MISO said it is not “seeking to assume the responsibility or to pre-empt the owner’s announcement of a generator retirement, but Attachment Y is late enough in the process for the owner to have made preparations for the decommissioning process.”
“We feel that it’s so late in the game, we don’t see it as detrimental to the asset owner,” Reddoch said.
PAC OKs Competitive Transmission Task Team Extension
PAC sectors approved a six-month extension of MISO’s Competitive Transmission Task Team.
Brian Pedersen, manager of competitive transmission, sought the extension to enable the group to continue identifying improvements to the RTO’s competitive project selection process in preparation for a future Tariff filing. The team was created after MISO selected LS Power to develop the Duff-Coleman 345-kV transmission project in December. (See Texas Law Could Affect MISO Competitive Transmission.)
“We want to make sure proposals take less time and money to evaluate,” Pedersen said.
The PAC allowed the extension by consent. Chair Cynthia Crane will report the extension at a July 26 meeting of the Steering Committee, which could ask why the group has not completed its original mission in the usual six-month time frame allotted to task teams.
MISO Extends Scoping for Long-Term Overlay Study
MISO will spend more time scoping its long-term overlay study, extending analyses into the first quarter of 2018 in order to better assess system needs.
MISO’s Lynn Hecker said the RTO needs more time to analyze system drivers of resilience and reliability 20 years into the future and discuss how the study will differ from annual Transmission Expansion Plan studies. In April, MISO released a preliminary overlay map of transmission needs that might be considered. (See MISO Planners Looking at 3 La. Projects, Overlay ‘Skeleton’.)
MISO canceled its next Economic Planning Users Group on July 27, where a discussion of the study was planned. Hecker said the RTO will plan a November special workshop to discuss scoping with stakeholders.
The extra quarter dedicated to analysis is not expected to alter the overall study timeline at this point, Hecker said. Projects resulting from the long-term overlay are not expected until the third quarter of 2018, with business cases discussed throughout 2019 before a targeted end-of-year approval on projects that make the cut.
Expedited Project Requests Move to MTEP 17
MISO is recommending that three expedited projects valued at $16.3 million advance to the 2017 Transmission Expansion Plan. Three other project requests are still under consideration.
Two southern Louisiana projects were recommended for MTEP 17 inclusion after reliability studies. Thompson Adu, senior manager of transmission expansion planning, said Entergy’s new $1.3 million Roux Substation and transformer upgrade will proceed, along with the company’s new $11.3 million Lyle Substation and associated rebuild of a 10-mile, 69-kV circuit.
MISO is also recommending ITC Holdings’ proposed $3.7 million, 120-kV Zephyr Substation and circuit in southeastern Michigan after determining the project will have no adverse reliability impacts.
The RTO is still assessing two substation projects in Iowa, Adu said. If approved, ITC would construct the $3.2 million Van Allen 69/12.5-kV and $2.2 million 69/25-kV West Okoboji Lakes substations.
“MISO is collaborating with transmission owners to perform a reliability no-harm test,” Adu said, adding that it should have recommendations on the projects by July.
Finally, Wolverine Power Supply’s $3.7 million Iron Works station and 120-kV loop project to support induction furnace load in southeastern Michigan has not turned up any reliability issues so far, but MISO is still studying the project, Adu said.
CARMEL, Ind. — Recent market developments are compelling MISO to reconsider how it weighs the relative importance of its 15-year future scenarios designed to inform its 2018 Transmission Expansion Plan, staff said last week.
“The final MTEP futures reflect the various opinions of this group,” Matt Ellis, a MISO policy studies engineer, told the Planning Advisory Committee at its June 14 meeting. He noted that the RTO sifted through 128 pages of stakeholder input to create the four recently completed futures.
MISO is proposing to eliminate futures weighting — which assigns a probability-based likelihood to each MTEP planning scenario — in favor of placing equal importance on each of the four futures. The proposal comes after stakeholders criticized the RTO’s weighting process for not being transparent enough. Some MISO South members called for less stringent carbon-reduction estimates. (See MISO Changes MTEP Futures Weighting for South.)
“It comes down to no one knows what the future will bring,” Ellis said. “The whole point with this that we’re truly trying to acknowledge is no one knows what is going to happen 15 years out, so let’s give them equal consideration.”
Uncertain Outlook for Carbon, Nukes
President Trump’s decision to withdraw the U.S. from the Paris Agreement on climate change prompted some stakeholders to ask if MISO should further reduce the 20% target carbon reduction in the accelerated alternative technologies future. (See Trump Pulling US Out of Paris Climate Accord.) Other stakeholders contend that some states’ renewed commitment to the agreement in the wake of Trump’s move indicated a possible need to increase the carbon-reduction constraint.
Ellis said MISO plans to keep the 20% carbon reduction measure. “It’s something we’ll keep an eye on,” he added.
Nuclear retirements easily earned the most stakeholder comment, according to Ellis. They were included last month as part of MISO’s fourth and newest future — a distributed and emerging technologies scenario. (See “MISO Tweaks 4th and Newest MTEP Future,” MISO Planning Advisory Committee Briefs.)
MISO will assume that 5 GW of nuclear will retire by 2032 based on the license expiration dates of five units in the RTO’s footprint, which include Callaway Unit 1 in Missouri, Clinton Unit 1 in Illinois, Palisades in Michigan, Point Beach Unit 1 in Wisconsin and River Bend Unit 1 in Louisiana.
Some stakeholders asked MISO to consider nuclear economic data in forecasting retirements, but Ellis reminded them that the RTO uses only public information to inform MTEP futures, precluding the inclusion of forecasted retirements based on the future financial viability of nuclear units, which is considered confidential.
Richard Seide of Apex Clean Energy said he was troubled that MISO would only use license expiration dates to forecast nuclear retirements. Ellis asked for stakeholders to submit their reasoning for including or removing other nuclear retirements from a future scenario.
Equal Weighting Spurs Doubts
Some stakeholders expressed surprise at MISO’s proposal to weigh all scenarios equally, saying they agreed on the futures under the assumption they would have input on weighting them.
“My concern boils down to: We’re pretty comfortable with the futures process now because we know we can weight them later. I think there will be a lot more focus on the development of futures,” WPPI Energy’s Steve Leovy said. He asked for MISO to delay finalizing the futures to ensure that stakeholders agree to those that could be applied equally across MTEP projects.
Stakeholders have until July 14 to comment on MISO’s proposal.
Ellis also said the RTO will attempt a series of workshops to improve project siting for the MTEP 19 cycle, especially for renewables. He said he would bring a proposal for workshops to the July Planning Advisory Committee meeting.
Electric Transmission Texas told ERCOT market participants last week that it is working closely with the ISO to minimize the economic effects of an 18-month project to repair cracks on metal transmission structures that will result in extended transmission outages through November 2018.
ETT, a joint venture between subsidiaries of American Electric Power and Berkshire Hathaway Energy, is currently inspecting transmission facilities on seven different 345-kV lines in Northwest Texas. The lines were all built as part of the Competitive Renewable Energy Zones (CREZ) project, which resulted in 3,600 miles of transmission to carry West Texas and Panhandle wind energy east to urban load centers. The project was completed in 2013 at a cost of $6.9 billion.
| Electric Transmission Texas
The transmission company notified market participants in May that it would be taking the CREZ lines out of service to inspect and, if necessary, replace structural components as part of a warranty claim. ETT said the work would involve visual and ultrasonic inspection of 2,743 structures, 21,944 arms, and 2,192 flanges and baseplates.
“Our contractors and suppliers are committed to completing things and not just doing the work to go home,” ETT President Kip Fox told market participants during a June 15 web conference. “We’re very confident we’re pursuing a solution that limits our costs to ratepayers, supports long-term reliability, improves safety and reduces the risk of unplanned outages.”
Fox and ERCOT staff both answered questions from market participants, many of them wind farm owners and developers.
In response to a written question about whether wind farms would be taken offline by the maintenance work, staff said its “current understanding” of the outage does not indicate that any generation resources will be “islanded” from ERCOT’s grid. The ISO expects some market participants will encounter congestion caused by the work, but it has not performed any specific resource analysis.
The Texas grid operator said it will schedule a second web conference to discuss an alternative ordering of the outages and address concerns about their effects on production costs.
Fox said ETT decided to address the structural issues now, “rather than the next 70-some-odd years.”
The company said it first discovered cracking on a structure arm in late 2012 and began a full inspection and arm replacement of more than 2,000 tangent poles in July 2016. The transmission structures are all steel, single-pole, 345-kV, double-circuit towers. Cracked arms and arm brackets will be replaced, and cracked baseplates and flanges will be repaired.
| Electric Transmission Texas
Inspection, repair and replacement crews are working in tandem, and line clearances will be taken continuously to help speed the work along. Outages will be scheduled one at a time and coordinated with ERCOT to minimize effects on the system.
A detailed work schedule and specifics on the outages’ timing and duration can be found in ERCOT’s outage scheduler.
CARMEL, Ind. — MISO’s human resources staff is looking for more ways to hire women and young people to diversify a workforce dominated by Generation X men.
The RTO’s annual workforce diversity results were presented during a June 15 conference call of the Human Resources Committee of the Board of Directors.
MISO is faring a bit better at overcoming its gender gap than the electric industry average: The RTO currently employs a 31% female workforce, while the average electric industry workforce average is 21% female. MISO said 36% of 2016 hires were female. The total U.S. workforce is about 47% female.
CEO John Bear said the RTO will continue to seek female representation in its workforce.
“The number of women receiving STEM [science, technology, engineering and mathematics] degrees is incredibly low. … It just means we have to fish from a smaller pond,” Bear said.
“We’re going to have to be super-focused on this to climb the dial forward,” Director Baljit Dail agreed.
MISO staff are also focusing on attracting millennials to close the generational gap across its employees. Generation Xers (ages 35 to 55) account for 62% of MISO’s employees. Baby boomers (55+) make up 13% of the MISO workforce and millennials (18-35) represent 25%. Electric industry employees in the U.S. are 50% Generation X, 26% baby boomers and 24% millennials.
Vice President of Human Resources Greg Powell said the age of MISO’s employees corresponds with its hiring boom after its was formed in 2001. He added that the “electric power generation, transmission and distribution workforce is aging much faster than the overall U.S. workforce and having great difficulty attracting millennials.”
Some directors expressed surprise that MISO’s workforce consisted of so few baby boomers.
Dail asked if there are any “hot spots” of baby boomers in any division that could be vulnerable to losing institutional knowledge through retirement.
“We don’t have critical positions that have an influx of people getting ready to retire,” Powell replied.
MISO is turning to its summer intern program to attract more millennials, Powell said. The RTO has hired 41 summer interns across its four locations this summer, up from 32 last summer. Powell said about 20% are women and 10 to 12% are minorities.
Bear said MISO is looking to increase the number of interns to about 50 in the next year.
“The interns are one of the best advertisements we have. We’re not a retail business, so as they go back into their academic communities … they’ll spread the word,” Bear said.
Powell said it’s MISO’s goal to hire about 50% of its interns on a permanent basis; it currently hires about 30%. “The challenge is these folks are pretty sought after,” Bear said.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following proposed manual changes:
A. Manual 14A: Generation and Transmission Interconnection Process and the Tariff. Revisions developed to the manual and the Tariff to allocate reinforcement costs of less than $5 million to all projects in a queue that add load to the violation causing the need for the reinforcement. Also removes alternate queue screening, allowing projects to be evaluated for impacts once the point of interconnection has been established. (See “Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues,” PJM Planning and Tx Expansion Advisory Committees Briefs.)
D. Manual 20: PJM Resource Adequacy Analysis. Revisions developed to address changes to modeling of zonal and global locational deliverability areas for capacity emergency transfer objective calculations. (See “ISO-NE out of this ‘World,’ According to PJM Reserve Requirement Study,” PJM Planning Committee/TEAC Briefs.)
F. Manual 39: Nuclear Plant Interface Coordination. Revisions clarify that nuclear operators must communicate any limiting conditions affecting interface requirements following notification of a grid-side event. The revisions, which include limits on the operability of offsite power sources, are intended to ensure that PJM and the transmission owner local control center have situational awareness of nuclear plant conditions.
3. Pseudo-Tie Pro Forma (9:40-10:15)
Members will be asked to endorse proposed pro formaagreements, along with corresponding Tariff and Operating Agreement revisions. A draft dynamic schedule agreement will also be presented, but it will be voted on at a future meeting. (See “Pseudo-Tie Discussion Postponed to Continue Negotiations with MISO,” PJM Markets and Reliability Committee Briefs.)
4. Regulation Market Issues Senior Task Force (RMISTF) (10:15-10:45)
Members will be asked to endorse the regulation market changes proposed by PJM and the Independent Market Monitor and endorsed by the Regulation Market Issues Senior Task Force. The changes affect benefit factors, performance scoring and settlements, and implements a 24-month transition plan. (See “Stakeholders Defer Vote on Regulation Revisions,” PJM Markets and Reliability Committee Briefs.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse:
B. Operating Agreement and Tariff revisions requiring solar generators to provide meteorological and forced outage data — previously only required from wind generators — in compliance with FERC Order 764. (See “Solar Forecast Is Coming,” PJM Planning and Tx Expansion Advisory Committees Briefs.)
C. Operating Agreement and Tariff revisions create a method for compensating pseudo-tied generators and dynamic schedules, which are not eligible to submit meter correction data, as permitted for internal generators and tie lines. (See “Meter Correction Initiative OK’d,” PJM Market Implementation Committee Briefs.)
D. Operating Agreement and Tariff revisions related to annual revenue requirements for new black start units. Sets deadlines for the submittal and review of new black start units’ capital, variable and fuel storage costs; policies for allocating costs to network service customers and point-to-point reservations. (See “New Black Start Units Will Have New Annual Revenue Requirements,” PJM Markets and Reliability Committee Briefs.)
1. Energy Market Uplift Senior Task Force (1:25-1:45)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions intended to preserve the benefits of virtual trading while eliminating opportunities for such transactions to profit from the market without providing benefits. Increment offers (INCs) and decrement bids (DECs) are permitted at locations where the settlement of physical energy occurs plus trading hubs; up-to-congestion transactions are permitted at hubs, zones and interfaces. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
CARMEL, Ind. — A quarterly IT scorecard audit has uncovered three technology-related issues for MISO staff to address.
In light of the audit, MISO will review a nine-hour website outage, continue to ensure that ex-employees don’t have system access 24 hours beyond their departure and commit more time to building its own settlement software system, the Technology Committee of the Board of Directors learned during a June 15 conference call.
MISO’s Carmel. Indiana Control Room in 2013 | MISO
MISO Technology Executive Kevin Caringer said the RTO will need an additional $390,000 to build its own settlement system software because staff were in some cases required to reverse-engineer the existing system to find original settlement software code.
Director Baljit Dail said the RTO should have all software code already documented as standard practice. “It gets into a very scary place where we want to change the code but we don’t know what the original code is or what it does,” he said.
Caringer said MISO had a majority of the original code and will run the old and new code in parallel for a few days until determining the success of the RTO-built system. If the new code fails, MISO will revert to the old code.
“We have done this in the past in the RTO as well for other major changes. It’s something we’re familiar with,” Caringer said.
He also noted that MISO will use the software to implement five-minute real-time settlements, which are expected in January.
The RTO meanwhile continues to strive to terminate the system access of former employees within 24 hours, Chief Information Officer Keri Glitch said.
“We are moving on a positive trajectory, and I have confidence we’ll continue moving forward,” Glitch said.
MISO has consistently scored near 100% in timely access terminations since February, up from a low of 42% in November. The RTO said access termination issues can arise when a third-party vendor fails to notify it when a contractor leaves.
Dail asked if MISO has any recourse if a vendor fails to alert it of exiting contractors.
Glitch said the RTO is developing new contract language setting out a procedure for vendors to notify it and terminate access.
The RTO is also reviewing a nine-hour public website outage that occurred from 4 p.m. to 1 a.m. on a Friday evening in March, after a physical network device failed and an employee exacerbated the situation by improperly configuring a switch-over to a backup device — leading to the outage.
“It appeared to be a human error,” Glitch said, adding that hardware components on critical network switches rarely fail.
Glitch said MISO is conducting a review of overall network design and failover capabilities when third-party vendors are involved.
President Trump’s nominees to FERC gave nearly identical, boilerplate answers to senators’ written questions on issues ranging from hydroelectric project licensing to natural gas infrastructure following their confirmation hearing last month.
The questions, mostly from Democratic and left-leaning independent senators, provide more insight into a party grappling with being in the minority under a presidential administration hostile to environmental issues rather than the nominees themselves.
Robert Powelson, a Pennsylvania Public Utility Commissioner, and Neil Chatterjee, senior energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), toed the FERC line, declining to answer questions about specific cases pending before the commission. The two, who were each approved 20-3 by the Energy and Natural Resources (ENR) Committee on June 6, are awaiting a confirmation vote by the full Senate. (See FERC Nominees Easily Advance to Full Senate.) No vote has been scheduled as of last week.
They pointed to recent technical conferences when asked about state energy policies and barriers to participation in the wholesale markets to energy storage, saying they were “eager” or “looking forward” to reviewing comments the commission has received.
They also provided similar answers to questions about Order 1000, about which nearly every senator who submitted written questions asked.
Senators expressed concern that there were still problems with the interregional transmission process. Sen. Joe Manchin (D-W.Va.) in particular quoted PJM CEO Andy Ott and SPP CEO Nick Brown’s criticisms of Order 1000 at the RTO Insider/SAS ISO Summit in March. (See PJM, SPP Chiefs Share Frustration with Order 1000.)
Both nominees said they were supportive of the order and pledged to carefully consider stakeholder feedback on last year’s technical conference. “I am a strong advocate for interregional transmission planning and, in my view, the commission’s implementation Order No. 1000 is a work in progress,” Powelson said.
The nominees also asserted that changes to how the commission administers the Federal Power Act, the Natural Gas Act and the Public Utility Regulatory Policies Act should come from Congress, not FERC.
Sen. Maria Cantwell (D-Wash.), for example, noted that while the electric industry is subject to mandatory cybersecurity standards, gas pipelines are only subject to voluntary guidelines issued by the Transportation Security Administration. She asked the nominees whether they agreed that there should be mandatory standards for pipelines.
“I defer to Congress and the Transportation Security Administration (TSA) as to the adequacy of TSA’s natural gas pipeline cybersecurity program,” Chatterjee answered. “Congress has granted TSA authority to establish mandatory cybersecurity regulations for natural gas pipelines.”
“Congress and the TSA are in the best position to evaluate TSA’s current natural gas pipeline security authority to determine if natural gas pipelines should be subject to additional or mandatory cybersecurity standards,” was Powelson’s answer.
Senators also asked questions particular to their individual states. Sen. Al Franken (D-Minn.) asked about problems with coal transportation by railway in Minnesota — another TSA issue, the nominees said.
But Sen. Tammy Duckworth (D-Ill.) asked about states served by multiple RTOs — which include Illinois. “States that are split into two RTOs are encountering issues where generating resources have been separated from the loads that they were built or contracted to serve,” she said. “How should proximity to resources, actual power flows and pre-existing transmission rights be considered in RTO modeling?”
Both nominees said they could not answer, as it was a question pending before the commission.
Environment and Climate Change
Powelson and Chatterjee’s deferral to Congress extended to questions about environmental impacts, climate change and increasing the use of clean energy resources, subjects about which every Democratic and liberal senator asked.
Sen. Bernie Sanders (I-Vt.), one of the three ENR members to vote against the nominees earlier this month, asked the nominees 52 questions — far more than any other senator — many of them related to the environment. Four questions asked in different ways whether the nominees accepted prevailing climate science.
Powelson and Chatterjee repeated their answers from their confirmation hearing that they understood climate change was real — and not a “hoax,” as Trump has claimed. (See No Fireworks for FERC Nominees at Senate Hearing.)
But they said it was not FERC’s place to regulate it or attempt to decarbonize the nation’s energy mix.
“Any policy to mitigate carbon emissions should originate in Congress; it should not be designed at FERC,” Chatterjee said. “Addressing climate change will require policy changes that the public accepts, and maintaining and enhancing affordability and reliability is vital to gaining that public acceptance. Should I be fortunate enough to be confirmed, my role as a FERC commissioner would be to ensure that any such policy not have a deleterious impact on reliability and affordability of our energy supply.”
“My understanding is that FERC’s policies are resource- and fuel-neutral,” Powelson said. “The commission relies on competitive markets to provide just and reasonable rates and reliable service for consumers, and to send appropriate investment signals for developers. … If confirmed, I will refrain from picking ‘winners and losers’ in the energy marketplace, as that is not FERC’s role.”
Questions by Sanders and others indicated their desire for FERC to slow down its approvals of gas pipelines. They asked the nominees if they agreed with former Chairman Norman Bay’s call for a review of the cumulative environmental impacts from Marcellus and Utica shale drilling. (See Bay Calls for Review of Marcellus, Utica Shale Development.)
While Chatterjee’s answer was anodyne — committing to working with his colleagues in reviewing commission policies — Powelson was more forceful in his answer.
“I respectfully disagree with that recommendation,” he said. “As a Pennsylvania state regulator … I believe that this issue would be better addressed at the state level. State environmental regulators and state public utility commissions are closer to the issues of shale gas development and are better equipped than the federal government to undertake such an assessment.”
Public Participation
Senators also expressed concerns about potential barriers to public participation in FERC’s processes.
“FERC is incredibly complicated, and the barrier to entry for someone to simply understand FERC proceedings, much less to participate, is extremely high,” Sanders said. “Stakeholders with considerable financial resources can participate, but everyone else is effectively excluded.”
Both nominees wrote that they would “work with my colleagues to identify further steps that FERC could take to make its proceedings and processes more accessible to the public.”
But Powelson also said, “I do not believe that the creation of such an office at FERC is necessary. In my view, the public comment process at FERC provides all interested parties with the ability to participate in the process and express their positions on issues.”
Duckworth also spoke up for public interest groups, saying they believe they have “an extremely limited voice in RTO stakeholder discussions, and RTO actions taken behind closed doors seem to be condoned by FERC.”
Last week, Virginia Democratic Sens. Tim Kaine and Mark Warner introduced legislation that among other provisions would mandate public comment meetings in every locality in the path of a proposed interstate gas pipeline. The bill is in response to complaints in the state about the limited opportunity for the public to provide feedback.
Republican Rep. Morgan Griffith, also from Virginia and a member of the House Energy and Commerce Committee, introduced a similar bill in the House.
AUSTIN, Texas — Potomac Economics’ David Patton told ERCOT’s Board of Directors last week that while the ISO’s market performed “competitively” in 2016, there’s still room for improvement.
Delivering an overview of his firm’s recent State of the Market report for the Texas grid operator, Patton said more efficiencies would be gained by improving the market’s price formation and, more important, real-time co-optimization of energy and ancillary services. Potomac Economics, ERCOT’s Independent Market Monitor, filed its most recent market report with the Public Utility Commission of Texas in May. (See “IMM Offers Additional Suggestions to Improve Markets,” ERCOT Briefs.)
“Co-optimization is our highest priority recommendation,” Patton said, noting that he has been making that same recommendation since ERCOT’s nodal market was developed last decade.
“Co-optimizing energy and ancillary services is one thing you can do to lower costs the most, and to ensure efficient pricing in real time,” he continued. “More importantly, co-optimization allows for efficient shortage pricing. With sustained shortages, there’s going to be a lot of revenue generated and lots of costs generated. Having a system where you are confident the use of resources has been maximized and the dispatch has been optimized, the shortages you’re pricing are real shortages, not an artifact of some dysfunction where you can’t get all the ramping capability of all your resources efficiently.”
Patton called real-time co-optimization a “more elegant process” than ERCOT’s current practice of “producing adders to try and mimic what a co-optimized system would do.” He said jointly optimizing the energy and reserve markets would allow shortage pricing under the operating reserve demand curve (ORDC) — which sets real-time energy prices reflecting the expected value of lost load — to be more accurate. The real-time market would determine every five minutes whether a shortage of either energy or reserves exists and set prices accordingly. Currently, capacity providing responsive or regulating reserves are not available to be converted into energy.
“Instead of producing an adder, you are allocating megawatts between products to manage constraints and satisfy load and reserve requirements,” he said. “When the system runs out of resources and can’t manage the reserve requirements, the marginal cost of the last megawatt of reserves you can’t satisfy will set the ancillary service price and be embedded in the energy price. If you’re in a transmission shortage and you’ve ramped what you can ramp, but you can’t get the flow beneath the limit, it will optimally establish congestion prices that reflect that transmission shortage.”
2016 ERCOT State of the Market Report
A co-optimized market would benefit ERCOT’s smaller qualified scheduling entities (QSEs) when they are allocated ancillary services, Patton said. QSEs with large portfolios can move reserves between generating units at lower costs, he noted.
“Co-optimization, with that full information in an optimal fashion throughout all of ERCOT … would allow the ancillary services to be optimized, because shortages of ancillary services set our shortage pricing,” he said. “Having confidence that’s done efficiently is important.”
The PUC has created a project to “assess price-formation rules in ERCOT’s energy-only market” (Docket 47199) and is planning a workshop for further discussion. The ISO is working on a report to be filed with the commission by July 14.
“We will be engaged in that with everyone else,” promised ERCOT CEO Bill Magness.
CAISO is kicking off an initiative that will consolidate proposed changes to the Western Energy Imbalance Market (EIM), including allowing third-party transmission providers to receive congestion revenue when they make capacity available between EIM balancing authority areas.
Stakeholders will discuss the proposals in a call later this month, and the changes will be submitted to the EIM Governing Body in October and the CAISO Board of Governors in November.
“The ISO is committed to providing ample opportunity for stakeholder input into our market design, policy development and implementation activities,” CAISO said in a June 13 issue paper that outlines the new proposals.
The initiative contains two other proposals in addition to the third-party transmission measure, including one that addresses monetary charges related to bilateral market schedule changes and another that provides for more equitable sharing of benefits when an EIM transfer wheels through an EIM balancing authority area.
CAISO said the proposal to allow third-party transmission owners to make available unused capacity for use in the imbalance markets would benefit market participants by increasing transfer capacity, while the transmission provider would receive congestion revenue. EIM entities can currently collect congestion revenue through an offset, but that functionality is not extended to third parties.
The ISO is also investigating whether it can use its current wheeling function to manage bilateral schedule changes originating within or moving across the EIM footprint. Under current practice, schedule changes made after hourly base schedules are submitted are exposed to real-time imbalance settlement payments that are not known ahead of time.
“This will allow market participants with potential bilateral transactions to express a bid price at which the balanced source/sink pair would result in a schedule change,” CAISO said.
Additionally, CAISO said it wants to explore whether balancing authority areas through which power is wheeled should share in benefits when energy transfers occur. EIM energy transfers through balancing areas are exempt from wheeling charges, and the market rule changes would allow the source, wheel-through and sink balancing areas to share in revenue recovery.
“In this case, analysis would need to be completed to determine the magnitude of net wheeling across the [balancing authority] and the cost associated with the wheeling that is not covered by the existing congestion rent settlement,” CAISO said. “This will likely vary per each EIM entity.”
Stakeholders will discuss the proposals in a June 20 call, with comments due on June 30 and a straw proposal to be posted July 27. More meetings are scheduled for August and September, with the board due to review a proposal in early November.
| CAISO
The CAISO-run EIM is designed to better balance supply and demand across the West by making more electricity resources available in real time. It began operating in November 2014 and now includes participants in Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming.
