Page 1142 – RTO Insider

February 5, 2019

ERCOT Technical Advisory Committee Briefs: Jan. 30, 2019

By Tom Kleckner

TAC Endorses Granularity to Ancillary Services Products

ERCOT stakeholders last week moved to address the Texas grid’s growing pains by tweaking the system’s ancillary service offerings, which predate the switch from a zonal to a nodal market in 2010.

The Technical Advisory Committee on Jan. 30 endorsed a Nodal Protocol revision request (NPRR863) that modifies responsive reserve service (RRS) to become primarily a frequency response service, allowing resources to earn compensation for providing primary frequency response (PFR). It also creates a new ERCOT contingency reserve service (ECRS), providing the grid operator with more “granular tools” to resolve low inertia levels caused by the changing resource mix.

The TAC gathers for its January meeting.

Electranet Power’s Marty Downey, representing the Independent Retail Electric Providers segment, pointed out that while wind energy and other renewables increase their presence in the ERCOT market, the ancillary services’ design has remained the same.

“Our grid has changed dramatically,” he said. “Wind energy continues to put pressure on ERCOT to address lower inertia. This gives ERCOT the tools to address that.”

South Texas Electric Cooperative (STEC), which sponsored the revision request, said RRS has been a staple of ancillary service offerings since the beginning of the zonal market. Its two components — PFR and 10-minute energy deployment — reflect the thermal generation technology available when the market opened, STEC said.

The co-op noted that NERC reliability standards require ERCOT’s online resources to provide PFR unless exempted by the grid operator. The system’s generation resources end up “providing an uncompensated service … and are subject to compliance risk” regardless of whether they have an RRS responsibility at the time, it said.

STEC also said ECRS provides ERCOT with additional flexibility while also “liberating” the 10-minute component from RRS. The co-op said creating two distinct ancillary service products removes barriers to entry, creates market efficiencies and appropriately compensates resources for the services they provide.

The Advanced Power Alliance’s (formerly The Wind Coalition) Walter Reid supported the NPRR. “Our members are all developing batteries and solar,” he said, pointing to more than 2 MW of energy storage in ERCOT’s interconnection queue.

“This is going to happen. We need to do things to facilitate this happening,” Reid said, calling for the revision request’s quick implementation.

As proposed, fast frequency response will be implemented in 2020 and ECRS no earlier than Jan. 1, 2022.

Stakeholders rejected a suggestion from industrial consumers, uncomfortable with the bifurcated approach and $2.5 million to $3.5 million in costs, to move implementation back to 2021 and 2022, respectively. An amended motion failed on a roll-call vote, gaining only 36% support.

The motion to endorse NPRR863 passed by an 86-14 margin. Luminant Generation, Reliant Energy Retail Services and industrial consumers voted against the measure.

South Texas Electric Cooperative’s Clif Lange

“The market does need certainty,” said Ian Haley, director of ERCOT regulatory policy for Luminant. “We have a fleet of generation resources that need to know what to provide. Having uncertainty seems scary to someone in our position.”

“We’re going to add a lot more renewables this year and next year. Inertia is going to be low,” said Sandip Sharma, ERCOT’s manager of operations planning. He said the grid operator hit 127 MW of inertia in 2018, its lowest level ever.

“ERCOT has been waving the inertia flag for several years. We’re on the cusp of that,” STEC’s Clif Lange said. “Now’s the time. … Holding off on PFR only increases the cost to consumers.”

Members Approve Urgent Battery Request

The committee accepted an urgent revision request that will allow Luminant to operate an energy storage system in West Texas, without setting requirements for future storage facilities.

NPRR915 defines batteries and other limited-duration resources and clarifies how their qualified scheduling entities should indicate to ERCOT their unwillingness to be deployed in real time, thus reserving the capacity for expected values above the energy-offer curve.

The measure, sponsored by Luminant, passed with one abstention.

Haley said as Luminant developed its 9.9-MW Upton 2 energy storage system, which became operational Dec. 31 south of the Midland-Odessa region, it became apparent the generator would have to register the battery under requirements not currently defined in the protocols. Upton 2, the largest storage project in Texas, was designed as a settlement-only resource, but it would have been required to register as a “capital G” generation resource.

Haley noted that while Luminant can update market offers from the battery, the fully charged resource will only last 4.5 hours when pushing its full capacity onto the grid, possibly leaving it “completely deployed and drained before those offers can take effect. This clarifies how we are supposed to let ERCOT know, ‘Please do not deploy the battery for the next [security-constrained economic dispatch] run.’”

Haley described NPRR915 as a one-off until ERCOT can get a handle on how to better accommodate battery storage systems.

“This shouldn’t apply to all batteries until we have a holistic view on all of this, but we should have a way for our battery to operate,” he said.

ERCOT said it plans to hold one or two workshops addressing energy storage issues, likely following the March spring break season. TAC Chair Bob Helton, of ENGIE, said the workshops will help determine whether to create a task force or turn the work over to stakeholder groups.

“We’re going to need a couple different set of rules for how batteries are operated, rather than shoehorning them into our existing software,” Reliant Energy Retail Services’ Bill Barnes said. “We encourage ERCOT to move forward [with the workshop] and get rules in place that make sense.”

ERCOT Director of System Planning Warren Lasher committed to previewing with the TAC at its next meeting a list of issues to be discussed during the workshops.

Reid was among several stakeholders urging ERCOT to hold the workshops as soon as possible. He reminded the committee that storage facilities are currently being registered in the market.

“The toe is in the water and batteries are hitting the ground, so the iron is getting ahead of the paper,” he said.

ERCOT’s RUC Activity Up over 2017

Staff’s annual review of reliability unit commitment (RUC) activity indicated a 14.2% increase over 2017, much of it to help resolve local issues with high load in the Permian Basin.

ERCOT’s 642 instructed resource hours in 2018 resulted in 613 effective RUC resource-hours, as compared to 562 and 534, respectively, for 2017. Staff said 22% of the effective resource-hours were bought back, resulting in a total RUC make-whole amount of about $460,000.

More than half of the total resource-hours came during the first half of May in the Permian Basin, where oil and gas production continues to drive much of the load.

In a separate required report, ERCOT’s Sean Taylor said the grid operator’s forecasted system administration fee of 55.5 cents/MWh for 2020 and 2021 will be “adequate.” Taylor said staff will provide an update when the commission weighs in on how it intends to fund real-time co-optimization.

Members Re-elect Helton, Coleman to TAC Leadership

The TAC re-elected Helton as chair and the Texas Office of Public Utility Counsel’s Diana Coleman as vice chair for 2019.

TAC Chair Bob Helton and ERCOT COO Cheryl Mele

The members also confirmed the leadership of its Protocol Revision (Chair Martha Henson, Oncor, and Vice Chair Melissa Trevino, Occidental Chemical), Reliability and Operations (Chair Kevin Bunch, EDF Energy Services, and Vice Chair Tim Hall, Southern Power), and Wholesale Market (Chair David Kee, CPS Energy, and Vice Chair Resmi Surendran, Shell Energy) subcommittees.

The Retail Market Subcommittee’s leadership will be confirmed at the TAC’s next meeting.

TAC Endorses PUC’s Changes to ORDC

Responding to a January directive from the Texas Public Utility Commission, the committee endorsed an Other Binding Documents revision request (OBDRR011) that modifies ERCOT’s operating reserve demand curve (ORDC), which provides a price adder during periods of generation scarcity. (See Texas PUC Responds to Shrinking Reserve Margin.)

The change shifts the ORDC’s loss of load probability (LOLP) curve by 0.25 standard deviations in 2019 and by the same measure in 2020. The use of a single blended ORDC curve is expected to lead to its more frequent use, and at higher levels.

The commercial and industrial consumer segments abstained from the vote. So did Direct Energy’s Sandy Morris, who said she continues to have concerns about consolidating the curves.

In “respectfully” abstaining, Thompson & Knight attorney Katie Coleman, representing the Texas Industrial Energy Consumers, noted her association’s longstanding opposition to the change and its potential increased costs.

“We’re still not in favor of it,” Coleman said. “In addition to not being comfortable with the magnitude of the shift, we’re also uncomfortable with combining the curves. It amplifies the pricing impacts.”

The PUC asked staff to provide to the commission a high-level implementation plan and timeline during its Feb. 7 open meeting. The grid operator is planning a March implementation.

The TAC also endorsed NPRR871, which had previously been tabled. The revision request gives ERCOT a mechanism to conduct a reliability review of customer- or resource-funded transmission projects, but without providing a recommendation.

“We don’t want the review process short-circuited by the project’s source of funds,” said STEC’s Lange, who helped supply the NPRR’s final language.

Jeff Billo, ERCOT’s senior manager of transmission planning, told stakeholders the grid operator would follow its normal study process in conducting the review, which would take 90 to 150 days. Billo said should staff identify a reliability or congestion problem, ERCOT would have the authority to recommend the project not proceed.

The TAC approved six other NPRRs, a second OBDRR and two Retail Market Guide changes (RMGRR):

NPRR850: Lays out principles for ERCOT and market participants to follow during a market suspension and restart and how activities will be settled.
NPRR8 86: Requires ERCOT, to the extent possible, to provide notice and allow time for comments before executing any new or amended agreement with another control area operator.
NPRR 910: Codifies eligibility, pricing and settlement for a resource that has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market and subsequently receives an RUC instruction.
NPRR 911: Reinstates previous language in the applicable protocol sections for determining online combined cycle generation resources’ (CCGRs) logical resource nodes’ real-time LMPs, following NPRR890’s approval. The LMPs will now be based on their weighted average at the resource node for each of the generation resources in the online CCGRs, using their real-time telemetered outputs to calculate the weight factor.
OBDRR010: Codifies that the high sustained limit will be included in the ORDC pricing’s online capacity for resources that have been awarded a three-part supply offer in the day-ahead market, but decide not to operate in the real-time market and subsequently receive a RUC instruction. Related to NPRR910.
RMGRR156: Moves ERCOT-specific market communication responsibilities to the Business Practice Manual while retaining retail-specific market communications and processes in the RMG.
RMGRR157: Allows transmission and/or distribution service providers to give an internet-based solution for safety-net submittals.

February 5, 2019

Senate EPW Committee Advances Wheeler Nomination

By Michael Brooks

The Senate Environment and Public Works Committee on Tuesday voted 11-10 along party lines to advance the nomination of Andrew Wheeler to be EPA administrator to the full Senate.

Acting EPA Administrator Andrew Wheeler at his confirmation hearing in January. | © *RTO Insider*

Wheeler, who has been serving as acting administrator since the July resignation of Scott Pruitt, was nominated to be the official head of the agency by President Trump early last month.

Republicans on the committee praised Wheeler for his work at the agency, while Democrats expressed concern about his efforts to roll back Obama administration policies on vehicle and power plant emissions — statements that largely echoed those made at his confirmation hearing Jan. 16. (See Dems Press E P A’s Wheeler on Climate at Confirmation Hearing.)

“It brings me no joy to say that he has not done what I had hoped he would do in a number of important respects,” Sen. Tom Carper (D-Del.), ranking member of the committee, said of Wheeler’s tenure as acting administrator. “In fact, in many instances, Mr. Wheeler has gone further than his predecessor in his rejection of important measures that are supported by a broad list of environmentalists and industry.”

Carper cited EPA’s prop o s al to rescind its finding under the Obama administration that it is “appropriate and necessary” to regulate hazardous air pollutant emissions from power plants under Section 112 of the Clean Air Act — a finding that led to the creation of the Mercury and Air Toxics Standards.

“In this MATS rollback proposal, EPA is willfully ignoring the actual benefits of reducing air toxics that permanently damage children’s brains and cause cancer, and ignoring the fact that the compliance costs were a third of what were originally estimated,” Carper said.

Ahead of the vote, Sen. Shelley Moore Capito (R-W.Va.) had raised concerns about a Politico rep o rt that Wheeler had signed off on a plan not to regulate two toxic chemicals, PFOA and PFOS, in drinking water. She joined 19 other senators from both parties in signing a lett e r Feb. 1 urging Wheeler to reverse that decision.

“Mr. Wheeler and his staff came to my office and addressed those concerns by pledging to look at all available statutory authorities EPA has been granted by Congress to address this potential crisis,” Capito said. “I intend to closely track the steps that EPA and other agencies are taking to address this public health and environmental health crisis, which has had a particular impact on West Virginians living in affected communities, to ensure that the federal government is sufficiently responsive to their concerns.”

February 3, 2019

PJM Weathers Arctic Blast

By Rich Heidorn Jr.

PJM survived last week’s arctic blast with slightly elevated outages and two periods of shortage pricing, officials said.

The cold air hit the Commonwealth Edison zone near Chicago first, with actual temperatures dropping as low as -24 degrees Fahrenheit on Thursday morning.

PJM issued cold weather alerts for the ComEd zone last Tuesday, PJM West on Wednesday and the entire RTO on Thursday and Friday.

Forced generation outages peaked at 10.6% of total capacity in PJM on Thursday (21,359 MW) after hitting 8.6% (17,275 MW) Wednesday. | *PJM*

Forced generation outages peaked at 10.6% of total capacity Thursday (21,359 MW) after hitting 8.6% (17,275 MW) Wednesday. That was below the 12.1% (23,751 MW) on Jan. 7, 2018, the peak day last winter, and less than half the 22% (40,200 MW) of the 2014 polar vortex.

Natural gas and coal generators represented almost 85% of the outages, including 2,930 MW of gas generation that was idled because of a lack of fuel.

Unit 2 of Public Service Enterprise Group’s Salem nuclear plant was forced to shut down at 3 a.m. Thursday after ice clogged the screens protecting its cooling water intake. Unit 1 also reduced power to 88% because one circulating water pump was shut down. Unit 2 was listed at 3% in the Nuclear Regulatory Commission status report Feb. 1.

PJM said the system energy price rose above $1,000/MWh early Thursday “following the loss of a generator in the eastern part of the RTO.” Synchronized reserve prices exceeded $900/MWh in the Mid-Atlantic Dominion (MAD) sub-zone and $600/MWh for the RTO.

Load for the week peaked at 139,452 MW at 8 a.m. Thursday, with LMPs rising as high as $144/MWh and synchronized reserve prices hitting $102/MWh.

Shortage pricing occurred both early Thursday and during Wednesday’s evening peak, following the forced outage of a generator in the western part of the RTO. Synchronized reserve prices hit $600/MWh in MAD and $300/MWh in the RTO, with energy prices peaking at $747/MWh for the RTO.

February 3, 2019

MISO Files New Planned Outage Rules

By Amanda Durish Cook

CARMEL, Ind. — MISO filed new requirements on outage coordination last week despite the fact that some stakeholders still aren’t entirely sold on the plan.

The Wednesday filing seeks to impose new generator accreditation penalties for planned outages taken during what MISO deems “low-margin, high-risk periods” (ER19-915).

Speaking at a Reliability Subcommittee meeting Thursday, Jeanna Furnish of MISO’s outage coordination team said the plan will incent the forward scheduling of planned generation outages. She said the RTO is now revising its Business Practices Manual language to match the Tariff filing should FERC accept the proposal.

“Increasing forced outage rates for generation in the MISO region, together with a significant correlation in the timing of planned generator outages and derates, have caused resource risk outside of the traditional summer peak times. This has created a new paradigm, where generator owners can no longer simply schedule their outages around peak load times to avoid operating risk,” MISO explained in its filing.

The RTO’s proposal would require generation resources to provide 120 days’ notice for planned outages, although those scheduled 14 to 119 days in advance would be exempt from accreditation penalties provided they are scheduled during predefined periods with adequate margins. Penalties would apply to planned outages and derates scheduled fewer than 14 days in advance and occurring during a declared maximum generation emergency. The proposal also provides safe harbor provisions for resources if a planned outage is adjusted at MISO’s request.

MISO has also proposed a transition period for the new rules, which would exempt outages scheduled prior to April 1 from the accreditation penalty. Requests and revisions submitted April 1 or later for outages starting April 15 through July 29 would be exempt from the penalty if the request is submitted no later than 14 days in advance and MISO foresees “adequate projected margin at the time of the request.” The full set of outage requirements will go into effect for outages scheduled to start July 30 or later.

While the rules are considerably less strict than the ones MISO had originally proposed, some stakeholders were still calling for more lenient requirements up until the time of filing. (See Stakeholders Press MISO for Flexibility in Outage Proposal.) Other stakeholders were repeating calls for the RTO to improve its own load forecasting.

In comments to MISO, Ameren Missouri said the two weeks’ notice requirement should be reduced to just one week, “more commensurate with the load and weather forecasting accuracy.” DTE Energy also called for a seven-day notice requirement in addition to a request that MISO provide daily updates to its Maintenance Margin, a nonpublic member webpage that keeps a monthly forward account of how many megawatts can be taken out of service without affecting reliability.

At least one stakeholder still had bigger problems with the outage coordination proposal.

“Reforms have been focused solely on penalizing generation owners,” Exelon’s David Bloom wrote. “Instead, MISO and its stakeholders should continue to examine ways to improve MISO load forecasting or consider new or modified requirements to use existing tools like the Maintenance Margin.”

Exelon also criticized MISO’s requirement to count a full 24 hours of a planned outage as forced when it is scheduled without the two-week notice and during a generation emergency, even when emergency conditions persist for shorter periods. The proposal is still “unduly punitive,” Exelon said. MISO’s proposal assesses a forced outage penalty against resource accreditation for a minimum of 24 hours or the overlap between an outage scheduled without the two-week notice and emergency conditions, whichever is greater.

February 3, 2019

NYISO Looks at Carbon Charge Credits, Tariff Changes

By Michael Kuser

RENSSELAER, N.Y. — NYISO stakeholders learned Thursday that pricing carbon into the wholesale energy market would have little effect on corporate credit rules and that any necessary changes will only be discussed after a second-quarter vote on market design and Tariff revisions.

ISO Manager of Corporate Credit Sheri Prevratil told the Market Issues Working Group (MIWG) that, based on the current market design, the only potential change might be to adjust the projected true-up exposure timing of transaction settlements to reflect the true-up timing of emission charges.

“Currently, that particular [timing] requirement is triggered off only the four-month true-up as a percentage of the initial invoice,” Prevratil said. “Depending on the timing of when those carbon true-ups come in, it may impact [that] and we might have to make a change on the trigger to the final bill closeout as it relates to the initial or formal settlement.

“But that’s the only one that right now I see might have to change as a credit rule,” Prevratil said.

If necessary, such rule changes would likely have to go through the ISO’s Billing, Credit and Accounting Working Group, and potential credit rule changes would not delay implementation plans for carbon pricing, she said.

New York’s Implementing Public Policy Task Force (IPPTF) in December turned its carbon pricing proposal over to the ISO’s stakeholder process through the MIWG, which began its work in January. (See Imports/Exports Top Talk at NYISO Carbon Pricing Kick-off.)

There may be more than one proxy generator bus at a particular interface with a neighboring control area to enable NYISO to distinguish the bidding, treatment and pricing of products and services at the interface. | *NYISO*

Energy Credit Components

NYISO will also evaluate potential adjustments in the external transactions component to account for carbon charges on imports and carbon payments on exports.

“Currently, we do anticipate that that carbon charge or carbon payment will just be a part of the daily net gains and losses, part of those calculations, and just summed up daily as the daily bill finalizes,” Prevratil said. “Carbon pricing will net in the daily advisory bill and will therefore net against daily energy purchases or sales in the Energy and Ancillary Services credit calculation.”

At the previous MIWG meeting, market participants expressed concern about a gross carbon charge that would be netted against the residuals in net cost, and that the resulting net amount would be further netted with all the other energy and ancillary services numbers that go into that calculation, she said.

The intent of the second part of the calculation is to capture changes, Prevratil said. “For example, we’re in a polar vortex right now. … If that run rate on average exceeds what we’re already holding, then you’re going to get a collateral call and it will be due two business days later. That will continue, but that’s a rolling 10-day run rate, so once those charges go down, then it will fall back to the first part of the calculation.

“We don’t anticipate changing the methodology of this,” Prevratil said.

The energy and ancillary services credit requirement equals the higher of the following:

The highest month’s price adjusted energy purchases in the prior equivalent capability period divided by the number of days in that month, multiplied by 16 days; or

The total average daily energy purchases incurred over the last 10 days, multiplied by 16 days.

New Tariff Sections

Pricing carbon into the wholesale energy market would require new Tariff sections related to applying a carbon charge, defining the social cost of carbon (SCC) and allocating carbon residuals, Ethan D. Avallone, senior energy market design specialist, told the MIWG.

NYISO’s Market Administration and Control Area Services Tariff (MST) would also require revisions to other sections, and subsequent Tariff presentations, including redline Tariff sheets, will build on the one considered at Thursday’s meeting, Avallone said. (See NYISO Looks at Carbon Charge Tariff Impacts, Residuals.)

As an example, Avallone pointed out, MST sections 7.2 and 7.4 would need to address emissions data reporting; section 17 would address the carbon component of the locational-based marginal price (LBMPc); section 23.3 would cover emission rates and reference levels under a carbon charge; and section 26 would cover any potential credit rule changes. NYISO will address those details when credit discussions begin this fall after approval of the carbon pricing market design.

Stakeholders asked what would happen to the ISO’s carbon pricing scheme if New York were to implement a carbon tax.

“We will follow what’s in the budget bill, and we will evaluate how it impacts NYISO’s efforts,” said James Sweeney, a senior attorney at the ISO. “We will make efforts in the Tariff such that entities don’t pay twice for carbon. How exactly it would be done is yet to be determined.”

The ISO foresees no revisions to MST sections 4.2 and 4.5, which describe day-ahead and real-time energy settlements, respectively, nor to guarantee payments such as bid production cost guarantees (BPCG), day-ahead margin assurance payments (DAMAP) and import curtailment guarantee payments.

NYISO’s current guarantee payment practices will continue under carbon pricing, Avallone said.

He emphasized that the ISO will charge each supplier on carbon emissions resulting from actual energy flows.

For example, NYISO will charge each supplier scheduling imports or pay each supplier scheduling exports the LBMPc at the relevant proxy generator bus, but the supplier will not be subject to a carbon charge or payment if the transaction fails in the ISO’s checkout process or is curtailed at the ISO’s request.

The latest NYISO schedule on carbon pricing calls for discussing LBMPc calculation and identifying marginal units on Feb. 15; Tariff revisions on Feb. 28 and March 18; and carbon bid adjustment for opportunity cost resources on March 4.

February 3, 2019

Xcel Again Betters Year-end Guidance

By Tom Kleckner

Xcel Energy last week reported that it once again met or exceeded its earnings guidance, posting year-end profits of $1.26 billion ($2.47/share), compared to $1.15 billion ($2.25/share) in 2017.

It was the 14th straight year the Minneapolis-based company had exceeded its own guidance.

Xcel’s fourth-quarter earnings were $215 million ($0.42/share), up from $189 million ($0.37/share) a year earlier. That met Zacks Investment Research’s consensus forecast.

Xcel continues to focus its efforts on clean energy. | *Xcel Energy*

Oil and gas production and strong economies in Xcel subsidiary Southwestern Public Service’s footprint drove a 1.3% increase in energy sales. The company expects flat sales in 2019, but it reaffirmed its 2019 earnings guidance of $2.55 to $2.65/share.

CEO Ben Fowke said the company’s clean energy transition continues to be a strategic priority. He said the company’s steel-for-fuel strategy has achieved a 39% reduction in carbon emission from 2005 levels. The company has set an 80% carbon-reduction target by 2030 and a goal of 100% carbon-free energy by 2050.

“Technologies have come a long way in the last 10 years, and it gives me confidence that our 100% carbon-free bill can be met as well,” Fowke said during a Jan. 31 conference call with financial analysts.

Xcel secured approval for more than 1 GW of new wind in Texas and New Mexico and 300 MW of wind in South Dakota. It completed construction of its 600-MW Rush Creek wind farm in Colorado and also acquired 70 MW of repowered wind energy.

Investors on Wall Street applauded Xcel’s performance, driving the company’s share price up $1.22 to $52.14, a 2.4% increase. It hit an all-time closing high of $53.68/share in December.

February 3, 2019

SPP Board of Directors/Members Committee Briefs: Jan. 29, 2019

By Tom Kleckner

Board Approves Modernized Cost-recovery Structure

NEW ORLEANS — SPP continued its effort to modernize its cost-recovery processes last week, agreeing to replace its broad single rate schedule with four targeted ones.

The Board of Directors approved the Schedule 1A Task Force’s recommended preliminary designs during its regular quarterly meeting. The group’s four rate schedules seek to better align beneficiaries with payers and include energy transactions in their design.

January’s Board of Directors/Members Committee meeting | © *RTO Insider*

The new rate design was approved by the Markets and Operations Policy Committee two weeks prior. The task force will now draft Tariff language and bring it back for approval in April or July. It has targeted implementation by June 2021. (See “1A Task Force’s Fee Schedules OK’d,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)

SPP says its current cost-recovery mechanism is based on a two-decade-old structure “that no longer aligns with actual use of our system.”

Under the new rate design, four rate schedules will replace the current one. Planning, scheduling and dispatch costs will be paid by transmission customers; financial administration costs by their users; market-clearing costs by virtual and real-time market participants; and markets facilitation by real-time market participants.

The task force agreed to use a mix of demand and energy charges, with market costs recovered through energy changes and planning costs through demand. Much of the debate centered on scheduling and dispatch costs, energy billing determinants and financial instruments, said Evergy’s John Olsen, the task force chair.

“I don’t think we made anyone perfectly happy throughout the process, but it was a great compromise,” Olsen said.

Oklahoma Gas & Electric’s Greg McAuley abstained from the Members Committee vote on the issue, saying his company wants to see independent generators paying their share of the costs.

“We don’t see Tariff language dealing specifically with that,” he said. “We thought this was a missed opportunity to address what we see as an inequity that exists now. We’ve got more generation in our [interconnection] queue than we’ve got load. This was an opportunity to take that uncommitted new generation and give it a stake in this infrastructure that accommodates them.

“We think it’s a move in the right direction. We’ll be watching and participating moving forward,” McAuley said.

David Osburn, general manager of the Oklahoma Municipal Power Authority, said he agreed in principle with the proposal, as market participants would be paying more of their share of the costs.

“Our concern was going from one charge to four. We just want to be careful not to make something more complex than it should be,” Osburn said. “As the real numbers develop, hopefully, we’ll get a better comfort level as we move forward. Being a small organization, we have difficulty covering all these activities.”

The task force was only formed last summer, but some of the work goes back several years, said Director Bruce Scherr, chair of the Finance Committee.

“We put a very significant stake in the ground here,” he said. “We can make refinements as we go through time. That’s not trivial, because it will require new filings at FERC. But it’s an important step in the right direction.”

OG&E’s Greg McAuley and Director Phyllis Bernard share a microphone. | © *RTO Insider*

Brown: SPP’s Prime Focus is RC Services in West

SPP CEO Nick Brown told the board and members that the grid operator’s primary goal this year will be to successfully implement reliability coordination services in the Western Interconnection.

The RTO recently said it remains on track to be certified in August and is scheduled to go live with its RC services on Dec. 3. It has signed RC contracts with about 12% of the load once served by Peak Reliability, which announced last year it would cease to exist by the end of this year. (See CAISO RC Wins Most of the West.)

“Entities coming and going in our footprint is not a new thing for us,” Brown said, referring to the additions of Nebraska public utilities and the Integrated System, and Entergy’s move to MISO. “It’s a new thing for entities in the West and for NERC. We’re very aware of NERC’s anxiety for taking what was performed under a single entity’s umbrella and bifurcating that under multiple entities.”

Also foremost on Brown’s mind is the Value and Affordability Task Force, which held its first “quasi-closed” session — members were allowed one representative to attend — on Jan. 30. Reporting directly to the board and led by Board Chair Larry Altenbaumer, the group is reviewing the cost recovery of transmission investments and the ongoing benefit being delivered from that investment and SPP’s operation.

“There’s significant confidential information that will have to be shared, if that group is to do its job,” Brown told members. “It makes me nervous. I compete with every one of you for personnel.”

Other SPP goals include:

Replacing the organization’s settlement system, which processes the more than $20 billion in annual revenues that flow through the markets. The project is behind schedule, but staff believe they can begin testing the system in May.
Improving generation interconnection processes.
Seeing conclusion of the work of the Schedule 1A Task Force and the Holistic Integrated Tariff Team, which are seeking to improve SPP’s transmission planning, markets and cost-allocation processes.

Members Increase Board’s Compensation

During a special Members Committee meeting, members sided with a Corporate Governance Committee recommendation and increased the board’s compensation for meeting attendance.

Directors will see their annual retainer raised from $30,000 to $50,000. Attendance at required meetings and board dinners will yield a total annual compensation increase from $81,000 to $101,500.

Brown said the CGC based its recommendation on recent research from NERC, two-year-old data from the ISO/RTO Council and a national association of board directors. On an annualized basis, he said, SPP directors’ compensation fell around the 50th percentile of the market.

Brown said SPP will work with compensation consultant Mercer this year to do a “full-blown” study.

Members also elected three representatives to three-year terms on the Members Committee: American Electric Power’s Peggy Simmons, representing the investor-owned utility sector; and Basin Electric Power Cooperative’s Tom Christensen and Tri-County Electric Cooperative’s Zac Perkins, representing the cooperative sector.

Perkins won a contest vote for his seat against Midwest Energy’s Bill Dowling, who was nominated from the floor without discussion.

GreenHat Energy Situation Unlikely in SPP, Director Says

Scherr told the board and members that an event similar to GreenHat Energy’s massive default on financial transmission rights in PJM’s market is unlikely to happen in SPP. PJM now estimates the event could cost its members more than $430 million. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)

“There are significant differences in the SPP markets, such as the level of congestion and structure of [FTR] products, which reduce the likelihood of this magnitude,” he said.

Scherr said he is heartened by the Credit Practices Working Group and Market Monitoring Unit’s oversight of the grid operator’s FTR markets.

Board Approves $1.8B in Transmission Projects

The board passed a consent agenda that included the 2019 SPP Transmission Expansion Plan (STEP) report, previously endorsed by the Markets and Operations Policy Committee. The report anticipates that an estimated $1.8 billion of projects will be built over the next five years in 13 states.

Also approved as part of the agenda:

Revision to SPP’s bylaws to allow any member to appeal to the board with a written request any action taken or recommended by an organizational group.
A Tariff revision (TWG RR237) that removes duplicative or unnecessary language in the SPP criteria to make it consistent with NERC Standard TPL-001-4’s requirements and account for the differences between NERC’s requirements and SPP’s Tariff.
East River Electric Power Cooperative’s sponsored upgrades of a new 115-kV line and a 115/69-kV transformer near Aberdeen, S.D. The project will be a creditable upgrade eligible for incremental long-term congestion rights or cost recovery through the Tariff’s Attachment Z2.
Modification of Westar Energy’s notification to construct a 345/138-kV transformer, requiring all elements and conductor to have an emergency rating of 440 MVA. The original requirement was 492 MVA.

February 2, 2019

NERC Seeks $10M Fine for Duke Energy Security Lapses

By Rich Heidorn Jr.

NERC has recommended a $10 million fine on an unidentified utility for repeated violations of critical infrastructure protection (CIP) reliability standards over more than three years that exposed a “lack of management engagement, support and accountability.”

Energywire and The Wall Street Journal reported that the unnamed utility was Duke Energy, one of the nation’s largest, with 7.6 million retail electric customers in six states and 49,500 MW of generating capacity. The company told the Journal it does not comment on enforcement filings.

The control room at Duke Energy’s Buck combined cycle plant in Rowan County, N.C. | *Duke Energy*

In a Notice of Penalty filed Jan. 25, NERC cited 127 violations between 2015 and 2018 (52 posing “minimal” risk, 62 “moderate” and 13 “serious”). While most of the violations were self-reported, others resulted from compliance audits (NP19-4).

Although many of the details were redacted as critical energy/electric infrastructure information (CEIl), the document refers to “companies” and “regional entities” in the plural, suggesting a large, multistate utility was involved.

“The 127 violations collectively posed a serious risk to the security and reliability of the [bulk power system]. The companies’ violations of the CIP reliability standards posed a higher risk to the reliability of the BPS because many of the violations involved long durations, multiple instances of noncompliance, and repeated failures to implement physical and cybersecurity protections,” NERC said. “As an example, the companies’ failure to accurately document and track changes that deviate from existing baseline configurations increased the risk that the companies would not identify unauthorized changes, which could adversely impact BES [bulk electric system] cyber systems.”

The notice cited as contributing causes “disassociation of compliance and security that resulted in a deficient program and program documents, lack of implementation, and ineffective oversight and training.”

It also criticized “organizational silos” illustrated by a lack of communication between management levels and “a lack of awareness of the state of security and compliance.”

There were also silos across business units “that resulted in confusion regarding expectations and ownership of tasks, and poor asset and configuration management practices,” NERC said.

In a settlement, the companies agreed to pay the fine and to improve their performance by increasing senior leadership involvement and oversight; creating a centralized CIP oversight department; and restructuring roles to focus on standards, enterprise oversight, enterprise CIP tools, compliance metrics and regulatory interactions. They also agreed to conduct industry surveys and benchmark discussions to develop best practices.

Redacted excerpt from NERC’s Notice of Penalty.| *NERC*

The companies also agreed to invest in enterprise-wide tools for asset and configuration management, visitor logging, access management, configuration monitoring and vulnerability assessments; increase training; and institute annual compliance drills.

NERC said the penalty was based on the companies’ “repeat noncompliance” and “deficient” compliance program, mitigated by the lack of evidence of any attempt to conceal the violations. The settlement and fines are subject to approval by FERC.

Among the most serious violations cited were:

A failure to protect critical cyber asset (CCA) information. One-line diagrams lacked the appropriate NERC ClP classification markings and some employees were improperly granted “read-only” access to CCA information.
A failure to follow its change control and configuration management process. In three instances, software upgrades were deployed on a single CCA in the production environment without first being tested as required by the change control process.
A failure to maintain annual cybersecurity training for some employees with electronic or physical access to CCAs.
A failure to timely revoke former employees’ and contractors’ electronic access rights.
Allowing individuals improper electronic access to CIP-protected information.
Improperly configured routers that prevented monitor server logs from being sent to the security incident and event management (SIEM) device.
A failure to monitor electronic security perimeter (ESP) inbound and outbound communications and to restrict inbound electronic access to ESPs. “The companies used overly broad ESP firewall rulesets, which permitted access across ports and services that were not required for operations or for monitoring CAs within the ESPs,” NERC said. “Additionally, the companies failed to implement strong technical controls to ensure the authenticity of the accessing party for [redacted] individuals who were granted unauthorized access to the ESPs.”
Firewalls were configured to allow external remote access to sensitive systems without first going through an intermediate system, using encryption or requiring multi-factor authentication.
A failure to implement physical access controls to limit unescorted access to the physical security perimeter (PSP) and failing to document all required information in visitor logbooks.
Repeated failures to adhere to cybersecurity testing procedures, including deficient testing on software upgrades and failures to implement security patch programs.
Failing to change passwords on annual schedule and failing to change factory default passwords for remotely accessible BES cyber assets.

Duke Energy Center, Charlotte, N.C. | *Duke Energy*

NERC’s filing came days before intelligence officials told the Senate Intelligence Committee on Jan. 29 that Russian hackers have the capability to disrupt electrical service in the U.S.

“Moscow is now staging cyberattack assets to allow it to disrupt or damage U.S. civilian and military infrastructure during a crisis and poses a significant cyber influence threat,” officials said in the annual Worldwide Threat Assessment.

“Russia has the ability to execute cyberattacks in the United States that generate localized, temporary disruptive effects on critical infrastructure — such as disrupting an electrical distribution network for at least a few hours — similar to those demonstrated in Ukraine in 2015 and 2016. Moscow is mapping our critical infrastructure with the long-term goal of being able to cause substantial damage.” (See DHS: 2017 Russian Probes Hit Hundreds of Energy Cos.)

The report also warned that China also “has the ability to launch cyberattacks that cause localized, temporary disruptive effects on critical infrastructure — such as disruption of a natural gas pipeline for days to weeks—in the United States.”

February 2, 2019

NERC Seeks $10M Fine for Duke Energy Security Lapses

By Rich Heidorn Jr.

It also criticized “organizational silos” illustrated by a lack of communication between management levels and “a lack of awareness of the state of security and compliance.”

There were also silos across business units “that resulted in confusion regarding expectations and ownership of tasks, and poor asset and configuration management practices,” NERC said.

Energywire and The Wall Street Journal reported that the unnamed utility was Duke Energy, one of the nation’s largest, with 7.6 million retail electric customers in six states and 49,500 MW of generating capacity. The company told the Journal it does not comment on enforcement filings.

Among the most serious violations cited were:

A failure to protect critical cyber asset (CCA) information. One-line diagrams lacked the appropriate NERC ClP classification markings and some employees were improperly granted “read-only” access to CCA information.
A failure to follow its change control and configuration management process. In three instances, software upgrades were deployed on a single CCA in the production environment without first being tested as required by the change control process.
A failure to maintain annual cybersecurity training for some employees with electronic or physical access to CCAs.
A failure to timely revoke former employees’ and contractors’ electronic access rights.
Allowing individuals improper electronic access to CIP-protected information.
Improperly configured routers that prevented monitor server logs from being sent to the security incident and event management (SIEM) device.
A failure to monitor electronic security perimeter (ESP) inbound and outbound communications and to restrict inbound electronic access to ESPs. “The companies used overly broad ESP firewall rulesets, which permitted access across ports and services that were not required for operations or for monitoring CAs within the ESPs,” NERC said. “Additionally, the companies failed to implement strong technical controls to ensure the authenticity of the accessing party for [redacted] individuals who were granted unauthorized access to the ESPs.”
Firewalls were configured to allow external remote access to sensitive systems without first going through an intermediate system, using encryption or requiring multi-factor authentication.
A failure to implement physical access controls to limit unescorted access to the physical security perimeter (PSP) and failing to document all required information in visitor logbooks.
Repeated failures to adhere to cybersecurity testing procedures, including deficient testing on software upgrades and failures to implement security patch programs.
Failing to change passwords on annual schedule and failing to change factory default passwords for remotely accessible BES cyber assets.

NERC’s filing came days before intelligence officials told the Senate Intelligence Committee on Jan. 29 that Russian hackers have the capability to disrupt electrical service in the U.S.

February 1, 2019

Judge Postpones Strict Probation Conditions for PG&E

By Hudson Sangree

A federal judge on Wednesday delayed his decision to impose extensive new probation conditions on Pacific Gas and Electric in its criminal case for the 2010 San Bruno gas line explosion, including a requirement that the utility inspect its entire grid for safety problems before the start of this year’s fire season.

Instead, Judge William Alsup, of the U.S. District Court for the Northern District of California, in San Francisco, said he would wait to the see the fire mitigation plan that PG&E files with the California Public Utilities Commission on Feb. 6, in compliance with last year’s SB 901. The judge also asked lawyers representing both explosion and wildfire victims to submit more information on fire safety measures they discussed at Wednesday’s hearing.

A section of the 30-foot gas pipeline owned by PG&E that exploded in 2010, killing eight people in San Bruno, Calif.

The hearing in the San Bruno case came a day after the utility and parent PG&E Corp. filed for bankruptcy, in part because they potentially face billions of dollars in liability for the fatal wine country fires of October 2017 and the Camp Fire in November 2018, which killed 86 people and destroyed the town of Paradise.

On Jan. 9, Alsup issued a tentative ruling in which he said that, unless the parties convinced him otherwise, he would impose new probation conditions on PG&E, which was convicted of six felonies for knowingly violating federal safety rules and obstructing a federal investigation after the 2010 explosion that killed eight people. (See Judge, Governor, CPUC and Protesters Weigh in on PG&E Mess.)

Those new conditions would include requiring the utility to reinspect its entire grid in the coming months and to remove any trees or branches that could contact power lines. In addition, he said PG&E would have to “identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions.”

The Camp Fire killed 86 residents and wiped out the town of Paradise on Nov 8, 2018. PG&E equipment is a suspected cause. | *NASA*

The utility “shall identify and fix damaged or weakened poles, transformers, fuses and other connectors; and shall identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires,” Alsup wrote.

“These conditions of probation are intended to reduce to zero the number of wildfires caused by PG&E in the 2019 wildfire season. This will likely mean having to interrupt service during high-wind events (and possibly at other times), but that inconvenience, irritating as it will be, will pale by comparison to the death and destruction that otherwise might result from PG&E-inflicted wildfires,” the judge wrote.

PG&E protested the proposed conditions, saying it would cost between $75 billion and $150 billion to comply with the requirements. Federal prosecutors also encouraged the judge to back down and defer to the federal monitor overseeing PG&E in the wake of the San Bruno case. (See PG&E Cleared in Fire that Burned Santa Rosa.)