If you are like me, some sounds drive you crazy. For example, nails raking across a blackboard have always made me cringe. Recently, another sound or comment has given me that same response. When I speak with companies about doing a compliance assessment, an internal controls evaluation or even a mock audit, often I hear, “We are good; we passed our most recent audit.” Someone may as well have just raked his or her nails across a blackboard.
Just ask the entities involved in the 2011 Southwest Blackout how passing an audit helped their case in the subsequent investigation. I will tell you. It did not help. Federal regulators assessed $37 million in fines and penalties as a result of that event. Arizona Public Service was assessed a penalty of $3.25 million despite having passed an audit earlier in the year. The Western Electricity Coordinating Council and Peak Reliability, WECC’s successor as the reliability coordinator for most of the Western Interconnection, was penalized $16 million. Peak had recently passed a NERC certification, which is essentially an audit of an entity’s readiness and capabilities. No one received a get-out-of-jail-free card.
Entities have regarded a good audit report as proof that they have a good compliance program. In fact, your audit report may be worthless. Regional Entities perform audits and send a report to NERC. Often these regional auditors are folks with whom you either worked or see so often you become friends. Many potential violations are often reduced to recommendations or suggestions resulting in a clean audit report. After all, I know “Fred” or “Sue,” and they will clean up these little nits.
What is overlooked or simply not understood is that if there is an event involving your company, an anonymous complaint filed against you or a spot check is performed that results in an investigation, your friends — oops, I meant regional auditors — will not be able to help you. NERC and FERC will step in and kick the regions out faster than a drunk uncle at the family Christmas gathering. NERC and FERC will go through your company with a fine-tooth comb, reviewing compliance documents, listening to voice recordings, conducting interviews and getting staff on the record. They will leave no stone unturned.
Not to mention, NERC and FERC have a higher standard than the regions. I know because I was a senior investigator at NERC and was responsible for conducting the above-mentioned duties, which resulted in millions of dollars in fines and penalties for entities. And remember, you do not have to be the utility that caused the event. Imperial Irrigation District (IID) was penalized $12 million even though they did not initiate the event. This is why I stress to my clients that I am not just preparing them for an audit, but also closing any compliance gaps in case there is a reason for NERC or FERC to come snooping around.
Leadership at utility companies must ask themselves if they are comfortable having a “check the box” compliance program, which meets the letter of the law, or a robust compliance program that meets the spirit of the law and would withstand the rigors of audits and investigations alike. Organizations owe it to their stakeholders to have a robust risk management program that will greatly limit its liability. If internal controls evaluations, mock audits and compliance assessments are not a part of the risk management strategy, I question leadership’s commitment to be the best it can be. There will be another event that will lead to another investigation, and stiff fines and penalties will be handed out. In the words of Bruno Mars, “Don’t believe me just watch.”
“But we passed our audit!” will not help the utilities involved. So, let me ask, has your company conducted an internal controls evaluation, compliance assessment or mock audit lately? And remember, I hate the sound of nails raking across a blackboard.
Terry Brinker, who has 23 years of experience leading, facilitating and implementing improvements in power plant operations, control room operations, compliance and regulatory matters, is the president of Reliable Energy Advisors. Terry previously served in leadership roles during a five-year stint at NERC, where he served as senior manager of standards information and personnel certification, manager of registration services, and senior event investigator.
FERC last week accepted Tariff revisions to streamline SPP’s Integrated Transmission Planning (ITP) process, despite opposition from wind developers.
The commission’s Dec. 21 order accepted the revisions as consistent with the transmission planning requirements under FERC Orders 890 and 1000 (ER17-2027).
SPP’s filing drew protests from the American Wind Energy Association, the Wind Coalition and four renewable energy companies. They contended that SPP’s ITP process did not meet Order 890’s transparency principle because it lacked details of the process currently found in the ITP Manual.
Arkansas transmission lines | MGN Photo
AWEA and the Wind Coalition also argued that the Tariff should “specify the transmission elements and voltage levels to which the ITP assessment applies; more clearly provide opportunities for stakeholder input on economic transmission needs; include additional details on the inputs SPP plans to incorporate into its planning studies and how SPP will determine the inputs to use; and explain how SPP will coordinate its aggregate transmission study, generation interconnection and ITP processes.”
The wind developers added that the Tariff, rather than the ITP Manual, “should detail how SPP determines the variable operations and maintenance cost for wind and solar resources; incorporate reasonable, objective standards to identify the amount of wind generation that SPP will use in its planning models; include triggers to address economic market conditions; and specify the criteria for identifying persistent operational issues.
FERC said the concerns “relate to elements of the ITP process that SPP does not propose to change, and thus are beyond the scope.”
“SPP’s proposed Tariff revisions implement this proposal without otherwise modifying the existing ITP process,” the commission said.
The protesters further argued that SPP should hold two planning summits per planning cycle, rather than the proposed annual summit. FERC agreed with the RTO’s argument that reducing the number of required planning summits “will not affect stakeholders’ ability to provide input.”
“Stakeholders may participate at the working group level and throughout the transmission planning process,” the commission noted, saying SPP could always schedule additional planning summits as needed.
Stakeholders approved the process changes, which were developed by a member task force, in July 2016. Under the new process, SPP will combine the ITP’s near-term and 10-year assessments and NERC transmission planning assessments into a single 10-year study. It also modified the 20-year assessment’s timing from at least once every three years to five years.
The changes will result in an annual transmission expansion plan addressing reliability, economic and policy needs. The first study under the new process began in September, and results will be unveiled in October 2019.
ISO-NE planning engineer Steven Judd on Wednesday described to the Planning Advisory Committee the key differences between the first and second phases of RTO’s System Operational Analysis and Renewable Energy Integration Study (SOARES).
While last year’s Phase I consisted of the RTO’s traditional economic analysis of scenarios provided by the New England Power Pool, this year’s Phase II focused on operations, requiring input data for wind, solar and electric vehicle charging to analyze intra-hour ramping, regulation and reserve requirements. Phase II will help inform stakeholders about the physical range of resource quantities that could be needed and available given the studied scenarios but will not indicate a requirement going forward, Judd said.
The 2017 study will be released in the first quarter of 2018, he said.
RTO’s Neighbors Seeing Similar Conditions
Michael Henderson, ISO-NE’s director of regional planning and coordination, told the PAC the RTO is seeing the same issues across the Eastern Interconnection, including a surge in distributed energy resources and the retirement of conventional fossil-fuel generators.
“Our other needs we see in New England we do not feel could be better met with additional ties with neighboring regions, and PJM and New York feel the same,” Henderson said.
He noted NERC’s recently published 2017 Long Term Reliability Assessment report, which showed slower demand growth across North America, with conventional generation continuing to retire and new additions of natural gas, wind and solar coming quickly online. (See NERC Report Urges Preserving Coal, Nuke Attributes.)
The changing composition of the resource mix calls for more robust planning approaches to ensure adequate essential reliability services and the fuel supplies. NERC said that 6,200 miles of transmission additions are planned to maintain reliability and meet policy objectives.
New Guidance on Asset Condition Presentations
ISO-NE lead engineer Michael Drzewianowski said the RTO is providing additional guidance to transmission owners regarding when they should present their asset condition needs to the PAC for inclusion on the RTO’s asset condition list.
Drzewianowski noted that a presentation is required if an asset condition need occurs on a pool transmission facility (PTF), and the associated cost of modifications on a single circuit or facility is $5 million or more over a period of five years or less.
For all other asset conditions related to PTF modifications, a presentation is optional. Non-PTF presentation thresholds are determined by each TO.
“It’s tough when each TO has its own idea on when an asset needs to be replaced,” but the planning process does work, Drzewianowski said.
National Grid Updates on NPCC Implementation Plan
Varsha Chatlani, a planning engineer with National Grid, told the PAC that his company estimates it will cost $12.4 million (with a tolerance of +50/-25%) to complete Phase 2 of a project to install dual high-speed protection systems on its PTF circuits. The company in June reported that Phase 1 would cost $1.8 million with a +200/-50% tolerance.
The project was developed in response to a 2015 Northeast Power Coordinating Council plan to install the protection systems on all bulk power system circuits over 10 years.
National Grid first laid out its implementation plan for 45 identified transmission circuits to the PAC in June. The company has started to develop conceptual cost estimates for the other three phases, and it will provide additional updates when more refined estimates are available, Chatlani said.
Eversource Energy has approximately 1,400 transmission circuit breakers in service and expects to spend nearly $20 million to replace 31 aged and obsolete oil circuit breakers (OCBs), company engineer George Wegh said.
1115kV OCB Catastrophic Failure | Eversource
Over the past 10 years, Eversource has been replacing OCBs with sulfur hexafluoride units to upgrade equipment and reduce maintenance costs. These upgrades protect the environment from oil spills and also improve system reliability by reducing equipment failures.
The 31 OCBs remaining on the Eversource 115-kV system are concentrated at three stations: Frost Bridge and Plumtree in Connecticut, and the Agawam station in Western Massachusetts. Three Frost Bridge OCBs are leaking oil.
Eversource recently replaced nine OCBs, not included among the 31 slated for replacement, on an emergency basis.
Further delay in replacing the obsolete OCBs would leave the transmission system vulnerable to age and condition-related reliability risks, and pose safety and maintenance concerns for the remaining circuit breaker fleet, Wegh said.
Eversource 345-kV Structure Replacement Projects
Eversource plans to spend an estimated $231.9 million to replace 1,019 wooden 345-kV structures with steel pole structures, John Case, the company’s director of transmission line engineering, told the PAC.
Poletop rot | Eversource
New England has seen a large increase in the population of pileated woodpeckers, “in the hundreds of percent according to some researchers,” and the birds are damaging old wooden transmission poles, Case said.
Eversource manages approximately 1,100 miles of 345-kV overhead lines in the region, or nearly 50% of such lines in New England, and maintains more than 10,000 345-kV structures. Inspections have revealed significant degradation and decreased load-carrying capacity of wooden 345-kV structures, many of which date from the early 1970s.
Replacing the structures resolves multiple structural and hardware issues, and supports safe and reliable operation, Case said. Hardware, insulators and guy wires are to be replaced along with the structures.
SEMA/RI 2027 Needs Assessment Scope of Work
Jon Breard, ISO-NE associate transmission planning engineer described the scope of work for the upcoming Southeastern Massachusetts and Rhode Island (SEMA/RI) 2027 Needs Assessment. The study aims to evaluate the grid’s reliability performance and identify reliability-based needs in the area for 2027 while also considering reliability over a range of generation patterns and transfer levels, he said.
A 2026 SEMA/RI Solutions Study report completed in March 2017 developed solutions to time-sensitive needs, which will be examined if any exist for the study area. Time-sensitive transmission needs are those that occur within three years of completion of a needs assessment. The RTO plans to issue the report in the second quarter of 2018. (See “Time-Sensitive Tx Needs Determination,” ISO-NE Planning Advisory Committee Briefs: Nov. 16, 2017.)
The short-circuit base case used for the SEMA/RI assessment is based on the expected topology in the 2022 compliance steady state base case. That year was chosen because “no significant project is expected in the 2022-2027 time frame, and the 2022 case was considered acceptable,” Breard said.
MISO won FERC permission last week to expand its mitigation measures to address intense but temporary congestion.
Thursday’s order allows MISO to begin enforcing dynamic narrowly constrained areas (NCAs) for short-lived congestion and market power Jan. 4 (ER17-2097-001). The RTO will extend Module D mitigation provisions in its Tariff to alleviate instances of momentary congestion that are not accounted for under its existing market power mitigation provisions.
“Establishing dynamic NCAs will improve MISO’s current market power mitigation procedures by providing an additional means to limit the exercise of market power during periods of transient but severe congestion,” FERC said.
MISO has five regular NCAs with conduct thresholds — prices that indicate potential exercises of market power — that range between $22.31 and $100/MWh. NCAs are defined by FERC as those constraints that can bind for more than 500 hours annually. They can be defined in advance and are subject to tighter market mitigation thresholds than broad constrained areas.
Dynamic NCAs will involve areas that do not meet the 500-hour trigger but need stricter thresholds because they are dominated by one or more pivotal suppliers, according to MISO.
A dynamic NCA would be declared when conduct has occurred that would warrant mitigation on a non-NCA constraint, and that constraint has bound in 15% or more hours over at least five consecutive days. The new category sets a conduct threshold at $25/MWh. MISO said it will terminate a dynamic NCA when either the outages or other conditions causing the binding transmission constraints have been resolved or the Independent Market Monitor hasn’t had to mitigate economic or physical withholding or uneconomic performance for 30 days.
“MISO explains that although a given transmission constraint is not expected to bind for a total of 500 hours or more in a given year based on historical data, thus not warranting an NCA designation, that constraint can ultimately bind over shorter periods at a rate that exceeds 500 hours per year (e.g., at a rate greater than approximately 9.6 hours per week),” FERC summed up.
FERC had issued a deficiency letter Sept. 6 seeking more detail on MISO’s proposal. In response, the RTO clarified that a dynamic NCA can be designated in the same area where a standard NCA already exists and provided FERC with a list of conduct categories and the conduct and impact thresholds for designating dynamic NCAs and mitigation. (See MISO to Address FERC Query on Constrained Areas.)
The Monitor first recommended creating dynamic NCAs in its 2012 State of the Market Report.
In accepting MISO’s new definition, FERC rejected NRG Energy’s argument that the RTO failed to take into consideration the differences between its Midwest and South regions by applying a uniform $25/MWh conduct threshold. NRG said that placing “unduly low thresholds” in MISO South could prevent generators from recovering their actual costs.
Clean Line Energy Partners announced Friday that it has sold all the assets of the Oklahoma portion of the multistate Plains & Eastern Clean Line transmission project to NextEra Energy for an undisclosed sum.
In a press release, Clean Line said the transaction would continue the “forward momentum” of the Plains & Eastern project and “install a new sponsor to a transmission solution to the burgeoning wind sector in Oklahoma” and SPP. Under the agreement, the company will retain its assets east of Oklahoma.
NextEra, which bills itself as the world’s largest generator of wind and solar energy, is the largest owner of wind generation in the Oklahoma, with 1.7 GW of operating capacity.
Plains & Eastern Clean Line Project Schematic | Clean Line Energy Partners
Clean Line spokesperson Sarah Bray told RTO Insider that while the Plains & Eastern’s goal is to “deliver low-cost renewable energy … to communities where there is substantial demand,” the market has evolved and eastern Oklahoma “now presents a strong delivery point for Plains & Eastern.” Alluding to NextEra’s financial strength and operational capabilities, Bray said, “We believe that they are the right owner to take the project over the finish line.”
Officials from the two companies have not disclosed the transaction’s terms, though it apparently includes the transfer of the “significant portion” of the Oklahoma right of way Clean Line has already acquired.
The Plains & Eastern is a proposed 720-mile HVDC transmission project that would move 4 GW of wind energy from the Oklahoma Panhandle through Arkansas to Memphis, Tenn., with a 500-MW drop-off in Arkansas. Clean Line has been involved in commercial negotiations with potential customers, both wind generators and load-serving entities seeking power.
Clean Line has said the project’s construction would begin once developers have contracts for 2 GW of capacity.
The project has been under development for eight years and has regulatory approvals from the Oklahoma Corporation Commission and the Tennessee Regulatory Authority. The U.S. Department of Energy issued a “record of decision” in 2016 after nearly six years of study and evaluation, saying it would participate in the project’s development under Section 1222 of the 2005 Energy Policy Act. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)
However, Clean Line has yet to receive a go-ahead from regulators in Arkansas, where the project has met stiff resistance from landowners and the state’s all-Republican congressional delegation. The lawmakers in March asked Energy Secretary Rick Perry to “preserve states’ rights” and reverse the department’s decision to partner on the project. They also are sponsoring a bill that that would prevent DOE from using eminent domain for Section 1222 transmission projects without the approval of both the governors and utility commissions of affected states.
But on Thursday, a federal judge in Arkansas rejected a lawsuit by two landowner groups challenging the department’s authority to partner with Clean Line. In his order, Judge D.P. Marshall Jr. of the U.S. District Court for the Eastern District of Arkansas overruled Downwind LLC and Golden Bridge LLC’s contention that the federal government exceeded its authority and denied landowners a chance to participate in the process.
“In the circumstances presented, Arkansas doesn’t get to decide where the transmission line is located,” Marshall wrote. “And the state doesn’t have a veto over whether this line gets built.”
Clean Line Executive Vice President Mario Hurtado applauded the decision.
“This critical decision confirms the strong legal basis for the Department of Energy’s decision to participate in the Plains & Eastern project, and keeps the door open for future infrastructure projects and the use of Section 1222,” he said.
WILMINGTON, Del. — PJM’s long-awaited capacity construct redesign will have to wait at least another month for endorsement by a key stakeholder committee, and its path to implementation includes additional hurdles after that.
Stakeholders at last week’s Markets and Reliability Committee meeting voted to defer an endorsement vote on the Independent Market Monitor’s MOPR-Ex proposal until the committee’s Jan. 21 meeting. PJM confirmed that even if it does receive endorsement, staff won’t recommend that the Board of Managers approve filing it for FERC approval; they will instead recommend their own proposal, despite not earning stakeholder endorsement.
John Horstmann of Dayton Power and Light made the deferral motion, which was seconded by Bob O’Connell of Panda Power Funds. Horstmann offered that a delay would give stakeholders a chance to review FERC’s response to the Department of Energy’s Notice of Proposed Rulemaking on price supports for coal and nuclear facilities, which is due by Jan. 11. It also provides additional time, without delaying a scheduled vote at the Jan. 25 Members Committee meeting, to review changes to the proposal requested by stakeholders and incorporated by the Monitor to secure endorsement. (See PJM Monitor Battles Exelon on MOPR-Ex Proposal.)
The proposal was developed by the Monitor as an extension of the minimum offer price rule (MOPR) in effect in PJM until FERC rejected it earlier this month on remand from a U.S. appeals court. (See On Remand, FERC Rejects PJM MOPR Compromise.) Its critics have been vocal, but it was the only proposal to receive endorsement at the Capacity Construct/Public Policy Senior Task Force (CCPPSTF), which spent the past year considering revisions to PJM’s capacity design. As the task force concluded earlier this year, many stakeholders preferred the status quo, but the RTO’s rules prevent that from being a voting option. Fearing that, without a clear stakeholder mandate, PJM would file its own two-stage repricing proposal, voters coalesced around the Monitor’s proposal, which is seen as having the least impact on the existing design.
But to secure enough votes for endorsement at the MRC, the Monitor revised the version approved by the CCPPSTF. That move has muddied the endorsement process and confused some stakeholders. It has also incensed other stakeholders, who argue that the Monitor is hypocritically picking winners and losers in drafting a rule ostensibly designed to avoid picking winners and losers.
Exelon’s Jason Barker questioned Monitor Joe Bowring on revisions to an exemption to the MOPR for resources developed under state renewable portfolio standards. Exelon, which offered its own two-stage repricing proposal in the CCPPSTF, contends that the Illinois zero-emissions credit (ZEC) program, which benefits several of its nuclear facilities, should be included in the exemption.
Bowring argued that he doesn’t “get to write the rules,” so his proposal must operate within the structures developed by states.
“We are taking those standards as they exist. … We deleted portions that would have resulted in most, if not all, RPS programs being not in compliance with this,” he said. “I know you would like to conflate ‘zero-emissions’ with ‘renewable,’ but they are not the same thing. This is the RPS, not the ZEC standard.”
In a subsequent email to RTO Insider, Bowring added that FERC has ceded regulatory authority over RPS programs and that the U.S. Supreme Court provided additional leeway for states in setting renewables standards in its decision rejecting Maryland’s plan to subsidize generation. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
As a result, there is only a limited ability for FERC-approved rules to affect the market participation of generation developed under RPS programs. The MOPR-Ex is intended to respect existing programs while introducing an element of competition, Bowring said.
“I can tell you most of the [state] advocate offices would not vote for the other version, but with this modification made … I think you gained the support of most of the advocate offices,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS). “Status quo is the preferred option, but this is the next best option because of the RPS exemption.”
Monitor’s Lead
The situation is further confused by PJM taking a back seat in developing necessary revisions to its governance documents.
“We are trying to facilitate at this point,” said PJM CFO Suzanne Daugherty.
Carl Johnson, who represents the PJM Public Power Coalition, took the RTO to task for what he saw as the “extraordinary” situation in which it would “not actively draft the Tariff language” for a proposal endorsed by a task force and said he plans to address it in the future.
Staff defended themselves, saying they “didn’t decline” to write the language but “engaged with the IMM staff and legal counsel” to determine that it might be better for the Monitor to write the first draft to ensure its intentions are accurately reflected.
“PJM is continuing to do its legal analysis, but PJM has been in close connection with the IMM,” PJM attorney Chris O’Hara said.
He noted that analysis might determine that applying the MOPR to any qualifying facility (QF) under the Public Utility Regulatory Policies Act isn’t defensible, “but that would entail a complete rewrite to what the stakeholder group did.”
PJM’s Stu Bresler announced that staff’s “recommendation to the board would be that we not file that proposal” because “it does not accommodate state public policy decisions” and raises discriminatory concerns.
Bowring responded that in the event of a “super-majority” stakeholder endorsement, “we would then consider making that filing ourselves, so one way or the other, we expect the proposal to get to the commission.”
Such a filing would be under Section 206 of the Federal Power Act, he confirmed.
Poulos asked whether PJM would recommend the status quo; Bresler clarified that is the pre-2012 MOPR rule, which was in place prior to the filing FERC recently rejected.
“No, that would not be our recommendation to the board,” he said, adding that PJM would recommend its repricing proposal to replace the existing MOPR rule.
MOPR Status
FERC’s rejection also muddies PJM’s capacity auction schedules. The RTO asked FERC for a waiver on its deadline for filing MOPR exemptions for its Feb. 26 Incremental Auction, PJM’s Jen Tribulski said. Generators will have until Jan. 12 to request exemptions for the third IA for delivery year 2018/19. Unit-specific exemptions for the Base Residual Auction for 2021/22 will be due on Jan. 10. All exemptions are based on the pre-2012 rule.
WILMINGTON, Del. — PJM’s initiative to internalize all generator payments moved forward at last week’s Markets and Reliability Committee meeting when stakeholders endorsed the RTO’s proposed problem statement and issue charge to examine price formation procedures for its energy markets.
Adam Keech, PJM’s executive director of market operations, faced scrutiny during an initial presentation Thursday, but returned later in the meeting with a significantly revised version that was endorsed by acclamation with 12 objections and 14 abstentions.
James Wilson, who consults with consumer advocates for several states within the RTO’s footprint, took issue with PJM defining the “price formation goal” as “maximizing the social welfare objective.”
“It sounds like the problem statement is trying to narrow what the stakeholder process can focus on,” he said.
Keech assured that wasn’t the intention. Caveats were added to the endorsed version to explain the objective and indicate that it was “in addition to” other goals.
He also said he was unsure if FERC’s order that day for the RTO to clarify or modify its fast-start resource pricing would be part of that evaluation. (See related story, FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Stakeholders sought assurances for a variety of tangential evaluations that Keech said PJM would undertake, though the endorsed proposal does consider as out of scope any discussions about impacts on and changes to capacity markets, among other things.
“I don’t think we have any intention of skipping out on the analysis here,” he said, but acknowledged “there may be other changes we’d like to make, but they’re not necessarily needed … for this group to move forward.”
Calling it a “dramatic change,” Independent Market Monitor Joe Bowring proposed an alternative analysis that called for individual examination of energy market components.
“If we’re going to do this review, let’s do it comprehensively so we come to the right conclusion,” he said.
“It’s a lot cleaner than PJM’s in terms of identifying the problem and what needs to be worked on,” Wilson said of Bowring’s proposal.
“I think there are some things in here that maybe give us a little bit of concern,” Keech said, but “the concept of including operator actions in LMP certainly [does] not.”
Because PJM’s proposal was endorsed, the Monitor’s was never considered for a vote.
Fuel-Switch Clarifications Endorsed
A debate that escalated at the Dec. 12 Operating Committee meeting was resolved after stakeholders endorsed clarifying text along with manual changes addressing gas pipeline contingency plans. The text box indicates that PJM “may need to direct” switching to an alternate pipeline or fuel on a pre-contingency basis and that it “will use best operator efforts” to move interruptible users off before firm service users. The revisions were endorsed by acclamation with seven objections and four abstentions.
Earlier in the meeting, stakeholders endorsed revisions to Manual 3: Transmission Operations and Manual 13: Emergency Operations, which include processes for addressing gas pipeline disruptions that affect generator reliability.
PJM’s Dave Souder announced that his staff are developing a problem statement and issue charge on the topic to be unveiled at the Jan. 10 Market Implementation Committee meeting.
Dave Pratzon of GT Power Group expressed concern that PJM “doesn’t have authority to tell a generator which” fuel source to use.
“This is a major expansion of PJM’s authority,” he said. “We need to think about it in terms of Tariff changes.”
O’Connell, who proposed the clarifying text, acknowledged the concern but said it will need to be addressed later.
“There needs to be some kind of bright line. How far inside the fence can PJM go?” he said. “We were in general agreement that trying to address those issues was more than we could bite off in the time frame we had.”
Incremental Auction Revisions Endorsed
Despite some stakeholder frustrations, proposed Incremental Auction (IA) revisions received endorsement with a sector-weighted vote of 3.55, surpassing the 3.33 threshold. They next go for endorsement at the Jan. 25 Members Committee.
The revisions — which would change in what IAs and for how much PJM can offer excess capacity commitments — received criticism at the Dec. 7 MRC for being presented as if the Incremental Auction Senior Task Force (IASTF) had endorsed them. In fact, the task force vote fell seven votes short of endorsement. Exelon’s Sharon Midgley moved for the vote.
Bowring criticized the proposal for making it “too easy to get out of your capacity commitment” and voiced support for PJM’s original proposal. The endorsed version was a variation of that proposal.
Marji Philips with Direct Energy reiterated previous criticism that “the process was subverted into a lot of other interests” away from the company’s original goal when it proposed initiating the IASTF.
“In this case, we believe this is actually worse than the status quo at this point,” she said. “This addresses a lot of other problems, but not the ones that it was initially designed to.”
“We support this package as a compromise,” said Susan Bruce, who represents the PJM Industrial Customers Coalition. “It is not perfect, but in this case, we do not want perfect to be the enemy of good enough. … We look at this as PJM taking on a commitment on behalf of load.”
“It’s not a benefit for load. It’s a benefit for suppliers because those suppliers with excess will be able to undercut” PJM’s mandated BRA price offer, CPower’s Bruce Campbell said. He offered to support anyone who motioned Package D, a competing proposal, but received no takers.
Customers, Competitors Battle TOs on Project Cost Caps
The fight over whether PJM should consider cost cap guarantees on more than construction costs in transmission-development proposals rages on.
PJM’s Sue Glatz presented proposed changes to the Operating Agreement that would include caps on construction costs in the RTO’s proposal evaluation, but LS Power’s Sharon Segner presented a counterargument that cost cap considerations should extend to factors such as return on equity and annual revenue requirements.
The proposal is “very divergent from other FERC-approved tariffs” and “doesn’t actually answer the question about how PJM will consider cost estimates versus cost-containment provisions,” Segner said.
American Municipal Power’s Steve Lieberman “strongly” supported Segner’s position, and Bowring also endorsed it.
Representatives of several transmission owners supported PJM’s proposal. Alex Stern of Public Service Electric and Gas and Tonja Wicks of Duquesne Light acknowledged they were initially against adding cost cap provisions but eventually changed tack.
“It was a balanced negotiation, so we relented to have cost cap language” included as long as it remained restricted to construction costs, Wicks said.
PJM’s proposal will be up for endorsement at the January meeting, and Segner will need to make a separate proposal if desired.
Acclamation Votes
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 1: Control Center and Data Exchange Requirements. Revisions developed to update NERC references and procedures related to outages and system-restoration planning. PJM members will be required to send the RTO data on transmission megawatt and MVAR flows and bus voltages at greater than or equal to 100 kV, down from 345 kV.
Manual 10: Pre-Scheduling Operations. Revisions developed to comply with NERC standards as part of a periodic review of the manual. Generators will be required to notify PJM of operating conditions that could result in a single contingency causing an outage of multiple generators.
Manual 14D: Generator Operational Requirements. Revisions developed as part of a periodic review. Generators will need to be modeled in eDART consistent with the PJM energy management system model.
Revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. Members endorsed the auction surplus proposal at the Dec. 13 MIC meeting, which allocates all surplus to auction revenue rights holders. The changes will be implemented for the 2018/19 planning period. (See related story, “FTR Changes in the Works,” PJM MIC briefs: Dec. 13, 2017.)
Members will be asked to endorse changes to the procedures for the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
The Arkansas Public Service Commission last week asked the D.C. Circuit Court of Appeals to overturn a FERC decision that rejected the state regulator’s request to exclude Entergy Arkansas from making backdated “bandwidth” payments to its affiliate companies.
The PSC made oral arguments before a three-judge panel on Dec. 15 in a bid to protect the utility’s Arkansas customers from bearing the costs of the payments (16-1193). A decision from the court is likely months away.
Under the Entergy System Agreement, which expired in 2016, low-cost Entergy operating companies made annual payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the Entergy system average.
The PSC is appealing FERC’s 2015 rejection of a request to shield Entergy Arkansas Inc. (EAI) from making $11 million in retroactive 2005 bandwidth payments and related interest assessed after EAI’s withdrawal from the system agreement in 2013. The state regulator contends the system agreement made no provision for assessing payments after withdrawal, which meant the utility had no continuing obligation to its sister companies (EL01-88-013).
FERC rejected the Arkansas commission’s argument that EAI’s 2005 bandwidth payments — $167.3 million for a seven-month period in 2005, plus $56.5 million in compounded interest — amounted to “exit fees,” saying the payments were “obligations specifically required by the system agreement and are for a period when Entergy Arkansas was subject to the system agreement.” (See FERC Sets Hearings for Entergy’s Cost Allocations.)
FERC also ruled that nothing in a previous order rejecting an Entergy compliance filing related to the agreement indicated that EAI would be excluded from further compliance filings.
Dennis Lane, lead counsel for the PSC, told the court the commission was not challenging an earlier figure of $156 million in 2005 payments, which he said EAI had already paid.
“We’re not asking [FERC] or the court to say we didn’t owe any of the bandwidth payment,” Lane said. “We’re not asking for [the $156 million] to come back. We’re just asking for the $11 million, plus any interest related to that, because that amount was determined after the system agreement was terminated.”
PSC Executive Director John Bethel told RTO Insider that if his agency were to prevail, “the preferential effect would bar payment of the payments and interest due after 2013.”
Lane told the court EAI is heavily reliant on coal, while its sister companies have a lot more natural gas generation.
“During the time period when the bandwidth got out of whack, natural gas prices were very high,” Lane said. “The bandwidth was a rough way to get those production costs back in.”
| Entergy
FERC framed the issue in a brief as whether “assuming jurisdiction, the commission reasonably determined that Entergy Arkansas remains obligated to make bandwidth remedy payments for a seven-month period in 2005,” notwithstanding its withdrawal from the system agreement.
The commission argued the time was not ripe for immediate judicial review. “The orders challenged here resolved only Entergy Arkansas’s liability for the 2005 bandwidth payments; they do not address the amount of that liability,” FERC said. It pointed out the liable amounts are the subject of “ongoing, vigorous litigation” before the commission.
“What’s going on at the commission is disputes over the actual methodology and the dollar figures,” said FERC counsel Carol Banta.
Entergy’s bandwidth payments have long been a source of contention for the five regulatory agencies that have jurisdiction over the corporation’s six operating companies. The system agreement and all of its service schedules ended in August 2016, with all of the operating companies having joined MISO.
Judge Patricia Millett at one point expressed surprise that Entergy was not represented in the courtroom.
“I’m kind of shocked they don’t seem to care at all,” she said. “They’re paying these millions and millions and millions of dollars.”
Banta said she could not speak for Entergy but responded with her understanding of the bandwidth agreement.
“Because they’re operating affiliates owned by a holding company, in most instances, as far as Entergy is concerned, it’s a zero-sum game. It’s one affiliate paying another affiliate,” Banta said.
CAISO’s Department of Market Monitoring on Wednesday discussed the ISO’s third-quarter market results with participants, but it referred a stakeholder query about a key development in the market to the ISO itself.
“It was an eventful quarter,” Lead Market Monitoring Analyst Amelia Blanke said during her presentation in the conference call.
The department noted that day-ahead system marginal prices hit $770/MWh on Sept. 1, when CAISO’s load came within 150 MW of its all-time system peak of 50,270 MW, set in July 2006. The Monitor said high temperatures and demand, along with the evening ramp-down of solar production caused the price surge. (See Tight Supplies, Solar Ramps Drive CAISO Summer Spikes.)
| CAISO Department of Market Monitoring
Powerex analyst Mike Benn pointed out that “load biasing” in CAISO has increased dramatically over the past year. Load biasing seemed to be too large, especially in the morning and evening hours when the system is ramping, Benn said, questioning whether the procedure was being used to correct inherent market flaws rather than adjust short-term deviations.
Load bias, also called “imbalance conformance,” describes the last-minute adjustments an operator makes to the load forecast ahead of a market run to account for potential inaccuracies and inconsistencies in the forecast. There are multiple reasons for adjusting loads, including managing load and generation deviations, automatically correcting time errors, variations in schedule interchange, reliability events and software issues.
“That is a valid question,” Director of Market Monitoring Eric Hildebrandt told Benn. “I think that should be passed on to the ISO. That is exactly why we provide this kind of information for stakeholders like yourself.” He added that CAISO “addressed the issue in various forums.”
CAISO indicated that third-quarter load adjustments in the hour-ahead and 15-minute markets climbed from about 600 MW last year to more than 1,100 MW this year.
In an attempt to address the issue, the ISO on Nov. 29 issued a straw proposal for “imbalance conformance enhancements” to clarify its authority to use the tool and implement process changes. The ISO expects to post a final draft proposal Jan. 24 and seek approval from the ISO Board of Governors in March. The DMM has voiced its support for the proposal.
The department said that most of the high prices during the quarter occurred as a result of high bids clearing the market, with extremely high bids in many instances clearing after use of the “load bias limiter.” Introduced in 2012, the limiter adjusts load in the market model to better reflect actual conditions during the market’s pricing run so that power balance is no longer being violated, reducing the potential for a “penalty parameter” to drive up the clearing price.
The DMM also said total payments for the ISO’s flexible ramping product were about $5.1 million in the third quarter, down from $7.5 million in the previous quarter. About 55% of payments during the quarter were made to generators in the ISO rather than external units.
FERC on Thursday ordered NERC to lower the threshold for mandatory reporting of cyber incidents, saying that the lack of any reports in 2015 and 2016 suggests gaps in the grid’s protections (RM18-2, AD17-9).
NERC’s Critical Infrastructure Protection (CIP) reliability standard only requires reporting of incidents if they have “compromised or disrupted one or more reliability tasks” (CIP-008-5, Cyber Security – Incident Reporting and Response Planning).
“Therefore, in order for a cyber-related event to be considered reportable under the existing CIP reliability standards, it must compromise or disrupt a core activity (e.g., a reliability task) of a responsible entity that is intended to maintain bulk electric system [BES] reliability,” the commission said. “Under these definitions, unsuccessful attempts to compromise or disrupt a responsible entity’s core activities are not subject to the current reporting requirements.”
In a Notice of Proposed Rulemaking, the commission said the standard should be revised to require reporting of incidents “that compromise, or attempt to compromise, a responsible entity’s Electronic Security Perimeter (ESP) or associated Electronic Access Control or Monitoring Systems (EACMS).”
FERC cited NERC’s 2017 State of Reliability report, which noted that “while there were no reportable cybersecurity incidents during 2016 and therefore none that caused a loss of load, this does not necessarily suggest that the risk of a cybersecurity incident is low.”
The current “mandatory reporting process does not create an accurate picture of cybersecurity risk since most of the cyber threats detected by the electricity industry manifest themselves in … email, websites, smart phone applications … rather than the control system environment where impacts could cause loss of load and result in a mandatory report,” NERC said.
Control room | Schneider Electric
The organization recommended redefining reportable incidents “to be more granular and include zero-consequence incidents that might be precursors to something more serious.”
NERC noted that the 2016 annual summary of the Department of Energy’s electric disturbance reporting form OE-417 included two suspected and two actual cyberattacks. In addition, the Department of Homeland Security Industrial Control Systems Cyber Emergency Response Team (ICS-CERT) responded in 2016 to 59 cybersecurity incidents within the energy sector, which includes the electric subsector.
“Based on this comparison, the current reporting threshold in reliability standard CIP-008-5 may not reflect the true scope and scale of cyber-related threats facing responsible entities,” FERC said.
Deadlines, Data Requirements
FERC said NERC’s revision should set a deadline for filing a report following a cyberattack attempt and specify the information required in the reports to “improve the quality of reporting and allow for ease of comparison by ensuring that each report includes specified fields of information.”
Schneider Electric acknowledged this month that its Triconex control system, which is used by power plants worldwide, was the target of an attack by nation-state hackers | Schneider Electric
Current rules require responsible entities to provide the Electricity Information Sharing and Analysis Center (E-ISAC) with initial notification within an hour of determining a “reportable” incident, which may be made by phone call, email or web-based notice. The rules do not specify what should be included in the report, nor do they set a deadline for completing the full report.
FERC said the reporting timeline “should reflect the actual or potential threat to reliability, with more serious incidents reported in a more timely fashion.”
The commission suggested requiring information on three “attributes,” as used in DHS’ multisector reporting and summarized in its annual report: the functional impact that the incident achieved or attempted to achieve; the attack method or “vector” (such as a phishing attack for user credentials or a virus designed to exploit a known vulnerability); and the level of intrusion that was achieved or attempted.
In addition to being filed with the E-ISAC, as is now required, the incident reports also would be sent to ICS-CERT. NERC also must file an annual — and public — summary of the reports with FERC with identifying details anonymized. “We believe that the ICS-CERT annual report, which includes pie charts reflecting the energy sector’s cybersecurity incidents by level of intrusion, threat vector and functional impact, would be a reasonable model for what NERC reports to the commission,” the NOPR said.
Comments Sought
Comments on the NOPR will be due 60 days after publication in the Federal Register. The commission specifically sought comment on whether to exclude EACMS from the new standard and establish the ESP as the minimum reporting threshold instead.
NERC defines an ESP as the “logical border surrounding a network to which BES cyber systems are connected using a routable protocol.” EACMS include firewalls, authentication servers, security event monitoring systems, intrusion detection systems and alerting systems.
“Therefore, EACMS control electronic access into the ESP and play a significant role in the protection of high- and medium-impact BES cyber systems. Once an EACMS is compromised, an attacker could more easily enter the ESP and effectively control the BES cyber system or protected cyber asset,” FERC said.
“The EACMS … are the systems that control access to the ESP. … You could consider it being the doorway,” Kevin Ryan, an attorney in the General Counsel’s office, explained during a presentation at the commission’s open meeting Thursday. “This … limits the proposal to high- and medium-impact BES cyber systems so we can see what happens in the future. But we’re not touching on low-[impact systems] at this point.”
The commission also asked for comment on alternatives to modifying the mandatory reporting requirements, such as whether a request for data or information pursuant to Section 1600 of the NERC Rules of Procedure “would effectively address the reporting gap … and satisfy the goals of the proposed directive.”
Safety ‘Pyramid’
The NOPR was approved unanimously.
“One thing that has been observed and studied across many industries — not just electricity but in aviation, medicine and other industries — is a well-established … statistical correlation between minor issues or near misses that are far more frequent and … rare major events,” said Commissioner Cheryl LaFleur, referring to what is known as “the safety pyramid.”
“We need to learn from the things that don’t happen but that could have happened in order to prevent the big thing that you’re afraid of happening,” she continued. “I think it’s important that we identify and track attempted incursions into the grid’s cyber defenses to help us learn from them, study the trends [and] see what we might need to do to standards.”
Commissioner Richard Glick, attending his first meeting, said, “We’ve been pretty lucky in the United States so far — at least on the electric side — in not having any significant consequences from cyber efforts.
“But we’ve seen it around the world already,” he added, noting the 2015 and 2016 attacks in Ukraine and Schneider Electric’s Dec. 14 disclosure that one of its control systems — used by power plants worldwide — was the target of an attack.
Malware
The attack, believed to be the work of nation-state hackers, targeted Schneider’s Triconex industrial safety technology, which is used by nuclear generators and oil and gas plants.
Triconex brochure cover | Schneider Electric
Investigators said the hackers used malware to take remote control of a workstation running Triconex’s safety shutdown system, then sought to reprogram controllers used to identify safety issues. One investigator called it a “watershed” attack that will likely be repeated.
The malware, which security firm FireEye named Triton, is the third type of computer virus known to be able to disrupt industrial processes. It was preceded by Stuxnet, which the U.S. and Israel allegedly used to attack Iran’s nuclear weapons program, and CrashOverride (also known as Industroyer), believed to have been used in the December 2016 attack in Ukraine. (See Experts ID New Cyber Threat to SCADA Systems.)
In proposing tighter disclosure rules, FERC also rejected The Foundation for Resilient Societies’ January 2017 petition asking the commission to set new standards for malware detection, mitigation and reporting (AD17-9).
The commission said new standards were not necessary based on existing reliability standards and ongoing efforts.
“For example, provisions of currently effective reliability standards, including CIP-005-5 and CIP-007-6, address malware detection and mitigation. Ongoing efforts described by NERC and other commenters, such as the development of a supply chain risk management standard, should also address malware concerns,” FERC said.
