WESTBOROUGH, Mass. — ISO-NE’s 2017 Economic Study will reflect the same basic assumptions and use the same profiles as those in the 2016 study, while representing some incremental changes to the former study’s third scenario. Marianne Perben, manager of resource adequacy and technical studies, outlined the 2017 study’s scope of work to the Planning Advisory Committee on Thursday, saying it will produce metrics similar to those in the 2016 report being completed now.
The 2017 study will include analysis that the Conservation Law Foundation requested at the April PAC meeting. The CLF wants the grid operator to determine whether there are viable system topologies other than those analyzed in Scenario 3 of the 2016 study with similar total system emissions but a lower relative annual resource cost.
Strong Mass. Economy Nudges up 2017 CELT Load Forecast
The 2017 Capacity, Energy, Loads and Transmission Report shows a reduced RTO load forecast from 2016 but predicts an increase in load for the Southeast New England area because the Massachusetts economy is growing faster than those in other New England states.
ISO-NE system planner Manasa Kotha on Wednesday presented a report on future capacity requirements, which credited some of the increase to changes in the operating company distribution of the load to the buses, and some to the Massachusetts economy, which is expected to grow at a compound annual growth rate of 2.1% through the forecast horizon.
The report covers net installed capacity requirements (ICR) for capacity commitment periods 2022/23 through 2026/27, ranging from 34,300 MW in the first cycle covered to 35,700 MW in the last.
| ISO-NE
The load forecast is net of behind-the-meter solar PV resources. Energy efficiency is treated separately — modeled as a supply-side capacity resource in the ICR calculations.
For additional background, Kotha referred participants to a Reliability Committee presentation on the ICR Values for CCP 2020/21 covered by Forward Capacity Auction 11.
Locational Reserves Good in Key Load Centers
Salem Harbor Generating Station
Generation and transmission additions expected to be completed by 2019 will ensure sufficient operating reserves in Greater Boston, Greater Connecticut and Greater Southwest Connecticut through 2021, according to a report on reserve needs for major import areas.
Forward reserve requirements for the Northeast Massachusetts/Boston zone have ranged from 300 to 500 MW for the last three summers, and 0 MW for the winters. The report calls for 279 MW this summer and 200 to 650 MW for 2018, dropping to 0 to 50 MW after the addition of the 674-MW Footprint Power quick-start combined cycle plant at Salem Harbor, which is expected online by the end of the year.
ISO-NE resource adequacy planner Fei Zeng, who presented the report to the PAC on Wednesday, said that fast-start resources near those major load centers provide flexibility to the grid.
WESTBOROUGH, Mass. — A substantial increase in new clean resources would lower Forward Capacity Auction prices, “crowding out” many existing resources — but their ability to do so will depend on the level of offer mitigation, according to an analysis commissioned by ISO-NE.
ISO-NE last year asked Analysis Group to assess outcomes in the Forward Capacity Market under six resource expansion scenarios evaluated in the second part of the 2016 Economic Study. (See scenario descriptions below.)
Todd Schatzki of Analysis Group briefed the Planning Advisory Committee on Thursday on the study, which assumes all current market rules. The study assumes retirements of 2,457 MW by 2025 and 4,668 MW by 2030. Absent retirements, Schatzki said, there’s limited need for new resources.
“Given low load growth, given what’s going on behind the meter and given that there is not necessarily a lot in the queue that is coming in, absent some market price signal, you’re not going to get new resources coming in,” said Schatzki, who prepared the report with colleague Christopher Llop. “You’re not going to get prices raising back up towards the cost of new entry unless some new resources get in the system.”
Capacity and Energy Market Implications
Total Forward Capacity Market payments in 2025 are projected to range between $2.1 billion in Scenario 3 (“Renewables Plus”) to $3.8 billion in Scenarios 2 (“ISO Queue”) and 6 (“RPS + Geodiverse Renewables”), with energy market revenues projected between $7.7 billion and $8.8 billion.
| Analysis Group
Scenarios with renewable additions would require additional revenue streams from outside the ISO-NE markets because they have a higher cost of new entry, the study says. Substantial expansion of clean resources as in Scenario 3 “would lower FCA prices, crowding out existing resources.”
“As the quantity of new clean resources added to the system increases, the cost (per MWh or MW) of supporting clean resources increases. The gap in revenue requirement (for new entry) needs to be filled by other sources because of decreases in revenues from both the FCM and energy markets.”
These impacts would depend on what portion of new renewables participate in the capacity auction and the extent of offer mitigation under the minimum offer price rule. The study assumes continuation of the current 200 MW/year renewable exemption, evaluating mitigation levels through sensitivity analyses.
Under four of the scenarios (1, 2, 5 and 6), the combination of energy, ancillary services and capacity revenue is sufficient to support the entry of new gas-fired combustion turbines. But market revenues are insufficient to incent the development of all other new resources assumed to enter the market in each scenario and none of the scenarios provides sufficient revenues for new combined cycle plants.
| Analysis Group
“Clean” resources — including offshore wind, hydro imports, battery storage and behind-the-meter solar, — would require other revenues, such as state renewable portfolio standards. “Needed revenues increase with the expansion of clean resources, as these resources reduce prices in both the energy and capacity markets,” the study says.
Total payments in the ISO-NE markets range from $9.7 billion to $15.6 billion, excluding ancillary service payments. The total payments do not include the costs associated with state policies.
ISO-NE completed Phase I of the Economic Study earlier this year and in June will issue the final part.
Robert Ethier, vice president of market operations, outlined the scope of work and for background information referred participants to a study on Forward Capacity Auction results published in December 2016.
Six Resource Expansion Scenarios
The resource expansion scenarios were:
S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.
AUSTIN, Texas — ERCOT stakeholders last week unanimously endorsed Oncor and American Electric Power’s 345-kV Far West Texas Project that addresses continued load growth southwest of Odessa, Texas.
Since 2010, the area has seen annual load growth of about 8%, driven by increases in the region’s oil and natural gas production. While demand growth projections have tapered off recently — only 2.4% through 2020 — Oncor predicts annual load growths as high as 11% within portions of the area over the next five years. More than 1,600 MW of solar resources are expected to come online during that time frame.
| ERCOT
Oncor and AEP’s original request to ERCOT’s Regional Planning Group last April estimated the project’s price tag at $423 million.
However, a staff review of 40 different alternatives lowered the cost to $336 million after settling on the most cost-effective of four options: two separate double-circuit 345-kV lines — each with one circuit in place — substation expansions and other transmission elements. One 85-mile line would run between the Riverton and Moss switching stations, with a second circuit added to the existing 16-mile 345-kV line between Moss and the Odessa line. A second, 68-mile 345-kV line would run from the Solstice switching station to the Bakersfield switch station. ERCOT concluded the upgrades “meet the reliability criteria in the most cost-effective manner and have multiple expansion paths to accommodate future load growth.”
Two of the other options would have closed the 345-kV loop between the two lines, while a third would operate the transmission lines at 138 kV on double-circuit structures. The costs ranged between $446 million and $501 million.
“My only concern is it keeps a tight bandwidth on future growth,” Oncor’s Collin Martin said during Thursday’s Technical Advisory Committee meeting.
Staff admitted the loop could be completed but said its recommended option would provide the best reliability solution while “augment[ing] the load-serving capability … as the outlook for greater load and generation resources in this region becomes more certain.”
The project has been proposed to go in service by 2022. Oncor, AEP and the Lower Colorado River Authority would be responsible for the parts of the project within their service territories.
The project still needs approval from the ISO’s Board of Directors and a certificate of convenience and necessity from the Public Utility Commission of Texas.
Rayburn Country Integration
Staff also updated the TAC on the potential integration of the 20% of Rayburn Country Electric Cooperative load that sits in the Eastern Interconnection. The East Texas co-op is considering connecting the load — approximately 190 MW — to ERCOT as early as December 2019. The ISO already serves the other 80%.
A study has identified a least-cost option of $38 million, primarily for a new 345-kV substation, a 138-kV switching station and the expansion of several 138-kV lines.
Southern Cross HVDC Project
TAC Chair Adrienne Brandt, of San Antonio’s CPS Energy, asked the Reliability and Operations Subcommittee (ROS) to schedule a joint workshop with the Wholesale Market Subcommittee to resolve issues arising from the PUC’s final scoping order related to an HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeast markets.
“This will ensure everyone has transparency between what the other group is talking about and make sure there are no conflicts,” Brandt said.
The PUC has directed ERCOT to complete a number of tasks before it allows the city of Garland to energize an approved 38-mile, 345-kV line that would interconnect the Texas grid to the Southern Cross DC tie in Louisiana. The tasks identified in the commission’s final order include determining Southern Cross Transmission’s “appropriate” market participation classification, necessary transmission upgrades and cost allocations, and resolving price-formation issues (Docket 45624).
ERCOT’s effort to increase visibility into distributed energy resources will begin at the subcommittee level after the TAC declined to get into an in-depth discussion of the growing challenge posed by small generation sources.
Saying she did not want to have the discussion at the TAC “just yet,” Brandt proposed starting it at the ROS. She did not receive any pushback.
ERCOT has proposed a collaborative process involving transmission and distribution service providers (TDSPs), “in which the locations of large DERs or large clusters of small DERs are mapped to their appropriate modeled transmission loads.”
The ISO has published a white paper, in which it proposes working with TDSPs to develop “a standardized method of providing and collecting appropriate data for mapping current and future registered DER units” to their common information model (CIM) loads. Staff said they will also work with stakeholders to develop a process for DSPs in competitive choice regions and non-opt-in entities (NOIE) “to monitor the accumulation of clusters of unregistered (less than 1 MW) DER units connected to specific CIM loads.”
Based on annual reports filed at the PUC, staff estimates nearly 900 MW of distributed generation were interconnected as of Dec. 31, 2015, along with more than an estimated 200 MW deployed in NOIE territories. (The reports use the terms DG and DER interchangeably.) Staff has added 20 new registered DER since November, giving ERCOT a total of 99 registered DER as of May 1.
The ISO suggests working with the TDSPs to jointly develop thresholds for “accumulations” of DER, reporting those that exceed the threshold and mapping clusters that exceed the threshold to a CIM load.
ERCOT defines DER as generation, storage technology or a combination of the two that is interconnected at or below 60 kV and operates in parallel with the distribution system. DER does not currently include demand response.
Woody Rickerson, ERCOT’s vice president of grid planning and operations, told the TAC the white paper builds on the Distributed Resource Energy Ancillaries Market (DREAM) task force’s work, which ended last year. (See “DREAM Task Force’s Work Now Ready for Stakeholder Process,” ERCOT Tech Advisory Committee Briefs.)
He said staff wants to produce annual reports so the grid operator knows how many DER are in its footprint and “what makes sense with aggregation.” Staff will insert the resources into the network model as it maps them to their CIM load points, improving the control room’s situational awareness.
ERCOT Reports Software Issue, Schedules Meeting on Outages
COO Cheryl Mele alerted the TAC to a market notice reporting on a May 22 incident in which a vendor’s issue-tracking system briefly allowed its software clients to view tickets from any other client, including ERCOT. Upon being notified by a non-ERCOT market participant and stakeholder, the ISO asked the vendor to shut down access to the system.
In the market notice, the ISO said it has been told a forensics team “has not found any evidence to suggest that information from ERCOT’s tracking system has been viewed by other software clients.” It is also conducting an internal investigation to evaluate the types of information in the tracking system and to try and determine who accessed or could have accessed the ISO’s information.
Mele also told the committee the Texas grid operator will host a June 15 WebEx on extended 345-kV outages in Northwest Texas this summer. Electric Transmission Texas (ETT) notified ERCOT on May 19 it would be inspecting a number of transmission lines ETT built as part of the Competitive Renewable Energy Zone and, if necessary, replacing components as a part of a warranty claim.
The outages are expected to last through November 2018.
Revision Requests Pass Easily
Confronted with 19 revision requests, the TAC separated onto a consent agenda those requests that had reached the committee unopposed or had impact assessments of more than $10,000.
The only nodal protocol revision request (NPRR) to receive an opposing vote was NPRR831, which also received one abstention, relating to private-use networks — networks connected to the ERCOT grid that contain load that is typically netted with internal generation and not directly metered by ERCOT. The change updates market systems to calculate a net load value for each private-use network that will be included in the load zone price for all markets, when the load is a net consumer from the ERCOT grid.
The NPRR was given urgent status to address instances in which LMPs do not reflect congestion. Kenan Ögelman, ERCOT’s vice president of commercial operations, said from a system perspective, “This is the quickest way to do this accurately.”
The committee passed NPRR827, which bars the ISO from awarding point-to-point (PTP) obligations in the day-ahead market when the corresponding clearing price is greater than the bid price by 25 cents/MWh or more, passed with one abstention.
ERCOT’s Carrie Bivens, manager of forward markets, said there is a market-design problem in the way PTP obligations are currently cleared in the day-ahead market. “We’re contemplating a different design choice for a long-term solution,” she said.
The committee unanimously approved NPRR830, which has an impact assessment of $120,000 to $160,000 and revises the basis of ERCOT’s calculation of the four-coincident peak calculation (4-CP) to be consistent with NERC’s net-energy-for-load methodology. The proposed methodology uses metered net DC-tie flows.
Members approved editing the business case to say the NPRR will “avoid rebilling costs resulting from the assignment of the 4-CP to an incorrect interval” and that it is consistent with direction from the PUC.
A pair of revisions to the Planning Guide (PGRRs) sailed through individual votes without opposition, but PGRR058, which clarifies specific generation to be included in the guide, was sent back to the Protocol Revision Subcommittee.
PGRR056: Accounts for potential subsynchronous resonance (SSR) vulnerability in the transmission planning process, providing references and citations to the appropriate protocol sections related to SSR and removing its definition from the guides. SSR is a potentially harmful phenomenon involving coincident oscillation between two or more transmission elements or generation resources at frequencies lower than the ERCOT system’s normal operating frequency (60 Hz). The change aligns the Planning Guide with ERCOT comments to NPRR562, which was also approved. NPRR562 clarifies responsibilities for affected entities and creates new requirements for the identification, study, mitigation of and protection against SSR. The ERCOT system has become more vulnerable to SSR because of the introduction of series capacitors for voltage support. Without proper mitigation, SSR can quickly destroy resonating elements and/or resources and lead to cascading outages. The NPRR was first introduced four years ago.
PGRR057: Aligns the Planning Guides with NERC Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing geomagnetic disturbance vulnerability assessments.
The consent agenda included three additional NPRRs, three changes to the Retail Market Guide (RMGRR), a change to the Verifiable Cost Manual (VCMRR), and revisions to the Commercial Operations Market Guide, Load Profiling Guide, Nodal Operating Guide and the Resource Registration Glossary. The guide and glossary changes expand the list of revision requests requiring ERCOT board approval and would first consider those revisions at the voting subcommittee level.
NPRR796: Specifies that character set validations are available within each Texas standard electronic transaction (TX SET) implementation guide, which recognizes all characters within the basic character set.
NPRR820: Aligns the definition of an aggregate generation resource (AGR) with the Protocols, which allow a resource entity to register several generators as an AGR. Intermittent resources are not included.
NPRR824: Aligns Protocol language with NERC reliability standards for energy emergency alerts (EEA) and real power balancing control performance.
RMGRR145: Provides the format for transmission or distribution service providers, municipally owned utilities and cooperatives to use a mass customer list to inform market participants of all customers in its service territories when entering competition or expanding its service territory.
RMGRR146: Expands the list of RMGRRs requiring board approval and provides additional clarifications to the RMGRR process.
RMGRR147: Updates protocol language by providing the option of generating a standalone invoice for meter tampering charges when there is no change in usage consumption.
VCMRR018: Aligns the manual’s revision process with the Protocols and market guides by changing the length of the comment period for newly submitted VCMRRs from seven to 14 days; requires review of all VCMRR impact analyses by the Wholesale Market Subcommittee; aligns the process for submission and review of urgent VCMRRs with other revision-request types; expands the list of VCMRRs requiring board approval; and provides additional revisions to mirror the Protocols and market guides.
ANCHORAGE, Alaska — Organized electricity markets could provide significant benefits for the West, but state regulators should approach their development with a critical eye, market leaders said last week.
“There is value in markets, and as a result, I’d encourage you to get educated about the benefits of them, and seeing also how it may get to change how you regulate utilities,” SPP General Counsel Paul Suskie said during a panel discussion entitled “Energy Imbalance Market or the Wild West Interconnect” at the annual meeting of the Western Conference of Public Service Commissioners.
‘Healthy Skepticism’
“Have a healthy skepticism. That’s what I used to be required to do,” the former Arkansas Public Service Commission chairman added.
EIM Governing Body member Carl Linvill, formerly a Nevada commissioner, recounted how his career path has imbued him with a dose of skepticism about markets. A former economics professor, Linvill moved to Nevada two decades ago to help build a market monitoring framework for the state’s proposed retail deregulation. In the wake of the Western Energy Crisis of 2000-01, the governor handed him the responsibility for unwinding the experiment in restructuring.
“My interest in coming out to Nevada for the job was [that] I was little bit concerned about over-optimism in the markets,” Linvill said. “I like markets, I think markets can be very beneficial, but I think that you have to have the right … legal structure [and] context for markets to work well.”
Linvill noted that each of the Governing Body’s five members is an outsider to CAISO, which operates the market. Members value the expertise of the ISO, as well as its state-of-the art operations, he said.
“But, also, having been outsiders and knowing that we need to be critical, we also take it as part of our job to question and challenge [ISO] staff and to try to push them to understand the perspective [from] our former roles,” Linvill said.
Linvill described to the audience of mostly commissioners and their staff how the Governing Body maintains independence from the ISO and exercises oversight over the market.
After originally being selected by a stakeholder nominating committee and approved by the CAISO Board of Governors, the body now approves its own members. The body — not the board — exercises “primary authority” over any ISO initiatives that wouldn’t have arisen without the existence of the EIM, meaning it can vote to recommend an EIM-related proposal.
“The Board of Governors can accept or reject, but they cannot amend or alter the proposal,” Linvill said.
Suskie touted the benefits of SPP’s own energy imbalance market — the precursor to the RTO’s current market — which saved members $1.1 billion between 2008 and 2013, far exceeding projections of $600 million.
“The higher the gas prices, the better the benefits of trading,” Suskie said, pointing out that the greatest savings occurred during the market’s early years when natural gas prices exceeded $7/MMBtu.
SPP’s incorporation of the day-ahead market in 2014 yielded another $1 billion in benefits, Suskie said.
While comparatively modest, the Western EIM’s benefits have grown consistently with the addition of new participants. The market now encompasses more than 50% of the region’s load, according to Stacey Crowley, vice president of regional and federal affairs at CAISO.
Crowley said the EIM has saved nearly $174 million since its inception in November 2014, including $31 million in the last quarter — an all-time high. (See CAISO EIM Exports Rise with Spring, Report Shows.)
Other benefits include the reduced curtailment of renewable generation, which can be offloaded into neighboring balancing authority areas, and sharing, which has reduced the need for EIM participants to carry flexible ramping reserves.
“The benefits continue to accrue,” Crowley said. “It really comes down to more efficient dispatch. It’s both interregional and intraregional. So we optimize within the balancing authority and between balancing authorities to really take best advantage of the resources that the Western utilities have.”
Qualitative Benefits
Linvill highlighted the importance of the qualitative benefits issuing from the EIM’s approach to dispatch.
“I think that a side benefit of this is that there’s much greater visibility within the utilities and within the [EIM] footprint region on what’s actually going on and what resources are available, what their capabilities are, [and] what the transmission system capabilities are. I think there’s much better information about that now then there was” before the market, he said.
Those qualitative benefits were enough to swing Arizona’s Salt River Project to join the market after determining that membership would be a financial “wash” for the publicly owned utility, Linvill said.
“I asked them, ‘How important were the non-quantified benefits, these other benefits?’ And they said, ‘Those were the driving benefits. We see this as an essential step to modernize our operations now so we can keep up as things evolve,’” he said.
Linvill said he has respect for markets that work well but recognizes that they can go awry.
“So, job one is to protect these benefits that have been created, to take this step-by-step, to add entities to the footprint, to potentially add services at some point. But we’re not rushing to that or even discussing that at this point,” he said. “Really, we want to make sure that we establish a market that has stability and robustness and continues to produce these benefits.”
Patrick Lyons of the New Mexico Public Regulation Commission questioned Crowley about whether EIM participants face exit fees.
“There is no exit fee. Entities can choose not to participate by just not bidding in resources or they can leave altogether, so that’s a nice benefit as well,” Crowley responded.
“So if a company wants to get out, and you’re counting on them being in there, how does that work? It doesn’t seem very stable,” Lyons said.
“I think that the benefit is that we’re not counting on them,” Crowley said. “This is above-and-beyond optimization that we do normally every day, so we’re going to continue to balance the load and resources based on what resources are available to the market.”
AUSTIN, Texas — ERCOT staff said its preliminary analysis of Lubbock Power & Light’s integration into the Texas grid reveals as much as a $66 million increase in production costs to serve the additional 430 MW of load.
| ERCOT
However, those costs will be offset to some degree by unlocking wind generation currently trapped in the Texas Panhandle. Integrating the LP&L system would require 141 miles of new 345-kV transmission lines — at a cost of $364 million — according to a separate ERCOT study completed last June.
Jeff Billo, ERCOT’s senior manager of transmission planning, said staff evaluated the years 2020 and 2025 with and without LP&L’s load. The analysis indicated an increase of $66 million and $60 million, respectively, in fuel costs to serve the additional load.
Billo said the final report will look at SPP’s production costs to determine the overall financial impact to the ISO. He declined repeated requests from Technical Advisory Committee representatives to discuss SPP’s preliminary numbers, saying only that the RTO’s production costs would decrease.
“Their decrease is less than our increase. That kind of makes sense, because we see an increase in the Panhandle’s export capability,” Billo said, referring to the transmission necessary to connect LP&L to ERCOT.
“We see more Panhandle wind getting to market with the Lubbock system integrated. The full cost of serving the load is somewhat offset by production-cost savings of [the] Panhandle wind,” he said.
| ERCOT
The integration would require ERCOT to update its systems and documentation to accommodate LP&L’s 115-kV facilities. The additional infrastructure will strengthen the Panhandle system and increase transient and voltage stability and reduce congestion. The LP&L load will also contribute to ancillary services’ costs.
Left undetermined is whether the load will be in its own transmission zone or absorbed into another, which would affect the congestion revenue rights process.
Final and more detailed information will be available in the report staff presents to the ERCOT board June 13 before a filing with the PUC.
Billo said SPP is working on a parallel timeline with ERCOT and will file its own report separately. SPP said Tuesday that filing will take place with the PUC in late June.
LP&L announced in 2015 it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. The PUC last summer asked the grid operators to conduct coordinated studies on the move, focused on a cost-benefit analysis for ratepayers. (See PUCT Asks ERCOT, SPP to Coordinate on Lubbock P&L Move.)
CARMEL, Ind. — A senior Homeland Security official told MISO employees and stakeholders Tuesday that cyberattacks will escalate in the future and the RTO and its members will be among the prime targets.
Neil Hershfield, deputy director of the U.S. Department of Homeland Security’s Control Systems Security Program, said of the 290 cyberattacks committed by nation-state terrorists that the department investigated in 2016, the energy industry accounted for 59, ranking third in targeted American industries behind critical manufacturing (63) and communications (62).
“Hackers are very interested in what you do,” Hershfield told MISO employees and stakeholders at a May 23 Informational Forum.
The department estimates that by 2020, 50 billion internet-ready devices will be in people’s hands worldwide. “All this adds up to a much-larger attack surface. It’s a long-term threat,” Hershfield said.
The number of sophisticated attacks will climb in the future, he said. “Frankly we anticipate more attacks, as hackers figure out how to monetize them like ransomware attacks,” referencing the international WannaCry ransomware attack, which held encrypted data in exchange for Bitcoin payments. Hershfield also said he believes that the 2015 attacks on power utilities in Ukraine were simply testing grounds for a larger attack. He said trojan malware ― like Havex and Black Energy, which was used in the Ukrainian cyberattack ― were used in most sophisticated industrial control systems attacks in 2014 and 2015.
“You might have to operate in a contested environment someday,” he warned.
The department categorizes cyber threats into three types: small groups or individuals who act out of notoriety or curiosity; criminals and activists that act on revenge or blackmail; and terrorist organizations and nation states with political motives. The government has identified hackers in Russia, China, Iran and North Korea, Hershfield said.
He said companies may have to operate in manual mode while they work to regain computer operations following a cyberattack. But that is not always possible.
“Many of the processes controlled by computerized control systems have advanced to the point that they can no longer be operated without the control system,” Hershfield said. Many of the employees who know how to operate in manual mode have retired, he added. “That’s something to think about.”
Hershfield also said the average company spends 2 to 3% of its information technology budget on cybersecurity, and best-in-class companies spend 8%.
Spear-phishing emails were the most common means of entry identified in the 290 attacks investigated by Homeland Security in 2016.
He said LinkedIn is hackers’ preferred starting point to gain access to work email accounts. “The main reason someone would go after you is access or placement in your organization,” said Hershfield, who advised employees with security access to be on guard, especially when opening emails. “Who here clicks on emails from their bank? I never click on emails from my bank. If I want to do something, I go to the bank’s website myself.” He also admitted that he recently earned low marks because of his Facebook account in a personal cybersecurity assessment. “I had my profile opened to everyone, not just friends,” he said.
Two-Password Authentication
Hershfield urges companies to limit remote access and isolate critical operating systems, recommending that all remote access be routed through a business network that doesn’t hold critical information. He also advised that MISO use a two-password authentication to access a critical control network, meaning one log-in and password for the business network and one for the critical control network.
“Is it less convenient? Yes. Is it more secure? Yes,” Hershfield said.
He also said companies should immediately terminate security access for employees that leave the company, pointing to a former Georgia-Pacific employee in Baton Rouge who remotely accessed computer systems and interrupted operations in February, causing $1.1 million in damage to the paper maker in retaliation for being fired. FBI agents arrived at his home to find a still-active virtual private network connection, Hershfield said. He said MISO and member companies should report control system cyber incidents and vulnerabilities to Industrial Control System Cyber Emergency Response Team by emailing ICS-CERT@hq.dhs.gov or calling (877) 776-7585.
Turbulent spring weather in MISO South and more expensive natural gas contributed to MISO’s highest energy prices since December.
Real-time energy prices averaged $30.03/MWh during April while day-ahead prices averaged $30.77/MWh, the first time prices have exceeded $30/MWh since December. The higher prices were due in part to about $3/MMBtu natural gas, and congestion from forced outages and high load in MISO South, which experienced severe weather and temperatures more akin to expected May levels. Systemwide load averaged 66.9 GW, a slight decrease from April 2016, and peaked at 79.6 GW.
“Operating challenges were few in the Midwest, but for the South, the opposite was true,” MISO Executive Director of Strategy Shawn McFarlane said at a May 23 Informational Forum.
McFarlane said MISO activated emergency procedures a number of times during the month in response to the weather and used its emergency pricing structure on three occasions in the month, one culminating in a maximum generation event on April 4. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs.)
McFarlane said MISO “successfully balanced supply and demand” during all emergency alerts.
“Fortunately, the actions of our neighbors and members and our own actions in the control room allowed us to navigate successfully through challenging events,” McFarlane said.
The Texas Public Utility Commission last week consented to a staff briefing order that lays out the issues to be considered in SPP and Southwestern Public Service’s joint request (Docket 46901) to determine whether Texas law includes a right of first refusal (ROFR) that overrides FERC Order 1000.
SPP and SPS filed a petition in February asking the PUC to consider whether the RTO can designate entities other than the incumbent utility to construct and own regionally funded transmission facilities in Texas outside the ERCOT service area. (See SPS, SPP Ask Texas to Rule on Transmission Competition.)
Transmission line foundation construction | Plocher Construction
At its May 18 meeting, the commission said the parties must address:
Whether an electric utility or other entity can construct transmission facilities in Texas without first obtaining a certificate of convenience and necessity from the PUC;
Whether the commission has authority under state law to grant a CCN to a utility that will provide only transmission service outside ERCOT; and
Whether SPS has the exclusive right to construct transmission facilities within its certified service area and, if it does, whether it can decline to exercise that right.
The commissioners directed the parties to not take up any issue “relating to the interpretation of a FERC order or tariff,” saying such issues are not within the PUC’s jurisdiction.
The briefs are due June 21, with reply briefs due July 6.
As an incumbent utility operating outside ERCOT, SPS contends the state’s Public Utility Regulatory Act (PURA) gives it a ROFR to build in the service area prescribed by the PUC. That would prevent a potential competitive project under Order 1000.
SPP claims that no such right exists, giving the RTO the ability to solicit and designate transmission-only utilities to construct and operate new transmission facilities within SPS’ service area under Order 1000.
The project in question, the 345-kV Potter-Tolk transmission line in the Texas Panhandle, was pulled from SPP’s 10-year planning assessment in April. SPP’s Board of Directors has directed staff to conduct a congestion study in the area, due within a year. (See SPP Board Cancels Panhandle Line, Seeks New Congestion Study.)
The PUC debated during its previous meeting whether to send the case to the State Office of Administrative Hearings (SOAH). The commissioners eventually agreed the docket could be decided based on written briefs. (See Texas PUC Agrees to Take up SPP, SPS Request on ROFR.)
SPS Rate-Recovery Request Moves Forward
The PUC also revised a preliminary order in SPS’ request to recover the cost of developing two wind farms in West Texas and New Mexico (Docket 46936).
Commissioner Ken Anderson directed staff to include in the order a discussion of the final approval’s effect on the city of Lubbock, which has said it wants to transfer load currently served by SPS from SPP into ERCOT. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
“Does it have the potential to create stranded costs that would have to be recovered?” he asked. “If the answer is yes, then the order should include a question about what should be done to eliminate that risk. It seems to me that because Lubbock has already filed to make that move, it shouldn’t be a surprise … that SPS will attempt to argue stranded costs. That issue should be teed up for the commission to consider.”
Anderson also asked SPS and its intervenors to address whether there should be a cap on costs — estimated at $1.6 billion, or about 40% of SPS’ rate base — as the PUC required of a Southwestern Electric Power Co. plant in western Arkansas.
“The truth of the matter is, we don’t know what the cost is going to be. It could result in very substantial increase in the rate base,” he said.
The company has asked the PUC to approve a “cost-reconciliation mechanism” for the period between the wind farms’ commercial operation date and their inclusion in the rate base. SPS has said it “cannot afford to wait eight to 10 months … to begin receiving revenue attributable to the facilities.”
SPS told the commission it hopes to have both wind farms in operation by the end of 2020, allowing it to capture the full federal tax credits. The two projects have a combined capacity of 1,000 MW.
The docket has been referred to SOAH. The Texas Industrial Energy Consumers and Golden Spread Electric Cooperative have intervened in the case.
The meeting was the PUC’s first without Donna Nelson, who retired from the commission May 15 after almost six years as the three-person panel’s chair. (See Texas PUC Chair Nelson Stepping Down.)
Her absence was notable from the start. With Nelson at the helm, Anderson would normally offer motions and Marquez would second them. On Thursday, Anderson had to prod Marquez into offering a motion to approve the consent agenda.
Momentarily flustered, Marquez said, “I’m sorry, that was a little out of order. You have that motion.”
Anderson seconded, and the hearing was underway.
Texas Gov. Greg Abbott has yet to announce a replacement for Nelson. The Texas Legislature’s 85th biennial session ends May 29, which may be delaying the announcement.
CARMEL, Ind. — Both MISO and PJM will attempt second drafts of their respective pseudo-tie requirements after receiving deficiency letters from FERC in response to their initial filings, officials said Tuesday.
MISO Director of Forward Operations Planning Kevin Vannoy confirmed at a May 23 MISO-PJM Joint and Common Market meeting that the two RTOs are working to respond to FERC’s requests for more information.
“Both RTOs are making administrative improvements that were intended for this year, but the commission rejected those, so we are continuing with those filings and continuing to work through the congestion overlap issue,” Vannoy said.
FERC’s May 5 deficiency letter asked PJM to explain how much it worked with MISO on the rules, how its proposed minimum electrical distance impedance was determined and how it will determine whether resources are operationally deliverable (ER17-1138).
MISO Senior Director of Regional Operations David Zwergel said his RTO still agrees that a revised pseudo-tie agreement will allow it to manage pseudo-tie impacts reliably. “It’s not infinite; there’s only so many pseudo-ties that transmission can handle,” Zwergel added.
PJM proposed that pseudo-ties be based on aligned network models from the two RTOs for flowgates and have firm transmission subject to a deliverability analysis similar to one it uses for internal resources. The RTO also proposed that any new flowgate created because of a pseudo-tie must have at least one flexible internal generator with at least a 1.5% impact on the flowgate.
“None of the current pseudo-ties fail this [deliverability] test … so we’re okay so far with that,” said Tim Horger, PJM director of energy market operations. Horger said PJM will again take up deliverability test specifics once double-counting complaints from MISO and PJM market members are resolved. “Once the dust settles from the FERC filings, we’ll work on that. We took a historical look at impacts so far.”
Customized Energy Solutions’ David Sapper asked if the RTO with the most stringent pseudo-tie rules would essentially determine what requirements new and existing pseudo-ties would follow.
“I guess you could look at it that way, but both requirements are going to have to be met,” Horger replied.
Some stakeholders expressed concern that MISO and PJM are still pursuing stricter pseudo-tie rules considering they don’t always bind at the same time on constraints.
Sapper also asked for more detailed Tariff filings from the RTOs on the second pseudo-tie requirement attempts, saying that MISO’s load-serving entities prefer more details, especially because the filings are “uncharted territory.”
Horger also said PJM is still pushing for its first-ever pseudo-tie pro forma agreement, which was debated for months this year before it was put on hold. Horger said if the RTOs agree on future rules laid out in their joint operating agreement, MISO would no longer need to be a signatory to the pro forma, and it could be limited to pseudo-tie owners and PJM. Horger said MISO and PJM staff are currently at work on joint operating agreement language.
However, Horger said PJM still isn’t in a hurry to finalize a pro forma. “We have the whole FERC quorum issue also; I don’t think there’s a rush to get this filed,” he said. The commission has been without a quorum since February, preventing it from taking definitive action on any disputes, including addressing the MISO Independent Market Monitor’s challenge to the pseudo-tie concept. (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)
RTOs Closer to Double-Congestion Rebate Program
MISO and PJM hope to implement rebates by September as a stopgap solution to the double-charging of congestion on pseudo-tied units.
The RTOs agree that day-ahead firm flow entitlement exchanges will improve predictions on the effect of congestion on pricing. The day-ahead exchanges between MISO and PJM began in late January.
Vannoy said in a best-case scenario, MISO and PJM can implement the stopgap rebate solution by the beginning of September and implement a longer-term goal of scheduling pseudo-ties in the day-ahead process by next May.
Four Categories for Freeze Date
Joe Rushing, a senior engineer in PJM’s interregional planning division, said the RTOs will continue to pursue a “bucket” approach to revise the current 2004 freeze date for determining eligibility for a share of firm rights on flowgates. The rights would be divvied up based on how long resources have participated in the market. (See “Freeze Date Future in Buckets?” PJM, MISO Go Quiet on Pseudo-Ties; Reach Interface Pricing Accord.)
The RTOs are proposing to add a fourth tranche to include market-wide transfers that align with planning processes. The tranche would be the first in line for a megawatt reduction when firm flow entitlements exceed a flowgate’s capability. The third tranche — which allows for entitlements to be granted for limited market-based transfers for reliability within the RTO balancing authority — will end after 10 years.
The first bucket will continue to be used for active designated network resources predating the current April 1, 2004, freeze date and historic transmission service requests, which will be given first consideration for flowgate needs. A second tranche would be for active designated network resources and transmission service requests after 2004.
Rushing said the RTOs will draft Tariff language for a FERC filing sometime in the third quarter.
The rush to build new generation in PJM might be over, if analysts are correctly reading the tea leaves of yesterday’s PJM capacity auction results.
Base Residual Auction prices for Delivery Year 2020/21 fell to $76.53/MW-day in most of the RTO, down from $100 last year. ComEd dropped to $188.12 from $202.77, and MAAC, which cleared with the RTO at $100 last year, dropped to $86.04.
The only areas that saw price increases were EMAAC, which jumped to $187.87 from less than $120 last year, and Duke Ohio-Kentucky, which cleared at $130 this year after pricing with the RTO last year. (See Capacity Prices down in Most of PJM in 1st Year of 100% CP.)
“The silver lining here appears to be a meaningful slowdown in new capacity clearing the auction,” UBS analyst Julien Dumoulin-Smith wrote in a note published Wednesday. “While it’s been years that many generators have been speculating on just when the flow of new units would slow, this appears it.”
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Less than 3,200 MW of new generation and uprates offered and just 2,824 MW cleared. Both results are down approximately 50% from last year’s auction. Clearing prices for 2020/21 ranged from only 26 to 66% of the net cost of new entry.
“To this end, we see the latest capacity prices and challenges in the debt markets as stymying any future efforts despite a clear backlog of future proposed plants,” he wrote. “We believe the market for new capacity is largely exhausted.”
Capitalizing on cheap fuel caused by an abundance of production in the Marcellus and Utica shale plays and pipeline constraints that limited takeaway capacity, developers flooded the market in recent years with new, highly efficient gas units that have depressed capacity and energy market prices. Low fuel prices persist, but the spark spread might not be as attractive anymore.
“I don’t see any economic justification for bringing a new power plant online” in these market conditions, ICF’s George Katsigiannakis said in an interview. “You start questioning what was driving all those builds: it was economics or it was just irrational expectations?”
Going forward, he said, “the market is going to rationalize and provide better returns,” but that will require unit retirements to reduce the excess capacity. With the onset of governmental initiatives to save certain units for socio-economic reasons, such as the zero-emissions credits passed last year in Illinois, and promote construction of others, such as renewable energy credits for solar and wind projects is several states, Katsigiannakis said “one of the most important issues” is how the oversupply will be curtailed.
“The intervention of state policies on the capacity market … how they can do it so they will not break down the market, is a different question,” he said.
Dumoulin-Smith agreed that he doesn’t “see any obvious easy fixes to improve prices” and that retirements appear to be a waiting game.
“The question is increasingly when will retirements materialize given the lower prices? We think any number of large legacy coal plants could see further pressure in [Pennsylvania and Ohio],” he wrote. “Even fully compliant larger plants could be at very clear risk across any part of the RTO footprint.”
He identified Talen Energy’s Susquehanna nuclear plant and Exelon’s Three Mile Island — which failed to clear the last three auctions — as potential casualties. He said Dynegy’s and FirstEnergy Solutions’ generation also is at risk.
Alternatively, he saw Public Service Enterprise Group, Calpine and Exelon as potential winners from the BRA, with their units concentrated in the higher-clearing locational deliverability areas.
Katsigiannakis said the “big surprise” was how much demand response was able to hang on despite the increased commitment demands of 100% Capacity Performance. He had expected DR to drop by about half from 10,348 MW to approximately 6,000, as that’s how much had year-round capability in last year’s auction. Instead, 7,532 MW cleared.
He said he’ll need to analyze the situation further to understand why so much additional DR was able to clear.
