ERCOT BoD Briefs: June 13, 2017

AUSTIN, Texas — Jeff Billo, ERCOT’s senior manager of transmission planning, told the Board of Directors last week that further analysis indicates Lubbock Power & Light’s potential transition from SPP could result in as much as $77 million in increased production costs — an $11 million jump from the preliminary results presented in May to the Technical Advisory Committee. (See Lubbock Load Could Boost ERCOT Production Costs by $66M.)

The increase did not go unnoticed by Director Carolyn Shellman, of San Antonio’s CPS Energy.

“So, you caught me on that,” Billo joked, when questioned about the difference. He explained the increase was caused by the addition of a third synchronous condenser to a previously approved project, designed to reduce wind energy congestion in the Texas Panhandle.

“Once we added a third [condenser], we didn’t see quite as much [economic] benefit from a wind-congestion relief perspective,” Billo said.

Staff’s evaluation indicates an increase of $77 million in fuel costs to serve the additional load in 2020 and $74 million in 2025. The preliminary numbers were $66 million and $60 million, respectively.

Should LP&L’s load be integrated into ERCOT, it will be placed in either the ISO’s West zone or its own zone. Analysis indicates non-LP&L consumers would see an increase of 3 to 5 cents/MWh in the years 2020 and 2025 to pay for serving Lubbock’s load.

Billo reminded the board that the increased production costs will be offset by additional wind energy flowing into the ERCOT market through the LP&L interconnection.

“The Lubbock Power & Light facilities create a new transfer path for wind energy out of Panhandle,” he said. “[The facilities] connect to wind resources where we’re seeing a lot of congestion.”

LP&L announced in 2015 it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. The Public Utility Commission of Texas last summer asked the grid operators to conduct coordinated studies on the move, focused on a cost-benefit analysis for ratepayers. (See PUCT Asks ERCOT, SPP to Coordinate on Lubbock P&L Move.)

ERCOT plans to file its study with the PUC by the end of June (Docket 45633). SPP has said it intends to file its study results with the commission in late June.

‘Healthy Margins’ Headed into Summer Months

ERCOT CEO Bill Magness said “healthy” reserve margins “well above our targets” have the grid in good shape to meet increased demand this summer. The ISO’s latest Capacity, Demand and Reserves report indicated reserve margins of 16.8 to 18.9% in the next five years. (See ERCOT Sees Enough Generation Through 2022, 73-GW Peak for Summer.)

ercot board spp — ERCOT CEO Bill Magness updates the Board of Directors on summer expectations. | © *RTO Insider*

ERCOT set demand records in both April and May, recording 59.2 GW on May 26 for its latest monthly high. The ISO has set new demand highs for seven of the 12 calendar months during 2016-17.

“Continuing growth on the system is pretty much evidenced by that fact,” Magness said.

Dan Woodfin, ERCOT’s senior director of system operations, said the ISO has sufficient resources (81.9 GW) available and doesn’t expect the Houston and Rio Grande Valley areas to be the “significant issues” they have been in recent years. He said transmission limitations may create congestion for exports from the Panhandle and imports into Houston.

Chris Coleman, the ISO’s meteorologist, said he doesn’t expect above-average temperatures in Texas this summer, despite the warmest winter on record. He shared data with the board that showed little correlation between warm winters and warm summers, and said it’s “highly unlikely” temperatures will reach the record-breaking levels of 2011.

“The main reason I won’t forecast a repeat of 2011 is because it’s wetter. Quite a bit wetter,” Coleman said, pointing to drought-breaking rains over the last few years that have raised reservoir capacity from 75.5% full to 87.2% in the last year. “We have 1.2 trillion gallons of water more than we did in the reservoirs in 2011.”

But Coleman told directors that Texas is long overdue for a hurricane’s landfall. The last storm to hit the state was Hurricane Ike, which devastated Southeast Texas in 2008. Another year without a hurricane’s landfall would equal the longest such span since 1900.

“We’re way overdue,” he said. “Statistically, we average one storm every 2.5 years.”

Coleman is forecasting 14 named storms and seven hurricanes, including four major storms. He is projecting three or four named storms in the Gulf of Mexico, where water temperatures never dropped below 73 degrees this winter.

“There’s a very strong correlation between a warmer-than-normal Gulf of Mexico and extreme weather,” Coleman said. He said there is a disturbance in the gulf over the Yucatan Peninsula and Bay of Campeche that could develop into a named storm (Bret) later this week, a forecast backed up by the National Hurricane Center.

Coleman has also been developing medium-range (eight to 14 days) and long-range wind forecasts (one to three months), work that’s still in progress. He said above-normal temperatures lead to windy conditions, and he expects a “windy” summer.

Board Vice Chair Judy Walsh asked Coleman whether he would begin to do wind forecasts that could provide meaningful data.

“That’s my plan,” Coleman said. “I just wrapped up this study, and I’ll try to apply it for the rest of the summer.”

Magness Unfazed by Lagging Admin Fees

Despite a $2.3 million negative variance in budgeted system administration fees, ERCOT still has favorable net revenues of $1.3 million — and little reason to worry, Magness said.

“Thinking about revenues in ERCOT in the springtime is sort of like Joaquin Andujar,” he said, referencing the late Major League Baseball pitcher. “Joaquin Andujar once said, ‘I can sum up the game of baseball in one word: you never know.’”

Magness noted that a year ago, revenues were down $2.2 million, yet the ISO ended up with a favorable variance. ERCOT is on track to finish 2017 with a $2.6 million favorable variance in net revenues.

“It’s all about managing to what we have,” he said. “We think we will come much closer to the forecast.”

Directors Approve 2018-19 Budgets, Keep Admin Fee Flat

The board unanimously approved ERCOT’s 2018-19 biennial budget, which includes $222.3 million and $228.0 million for operating expenses, projects and debt-service obligations for 2018 and 2019, respectively. The ISO is currently operating under a $223.1 million budget.

The 2018-19 budget keeps the system administration fee flat at 55.5 cents/MWh. It was raised from 46.5 cents/MWh with the current budget, approved in 2015.

Walsh, who chairs the Finance and Audit Committee, said projections through 2023 show load growing at almost 2% and labor costs escalating at 4% annually. She said committee members asked ERCOT staff to come back in August with analysis on how to keep from raising the admin fee.

“As we look out further in time … and if these assumptions prove true, we’re going to have to balance the levers we have,” Walsh said, referencing FTR revenues, credit revolvers and the admin fee. “We want to explore how each of those moving parts work, so we’re fully apprised of what our choices will be, should we continue to have higher growth in expenses than load,” she said.

After 4 Years, NPRR Gets Unanimous Approval

Nodal protocol revision request (NPRR) 562, four years in the making, was among 10 changes unanimously approved by the board.

“This was a very challenging issue,” Magness said. “You notice the NPRR started with a five. Everything else [on the agenda] started with an eight.”

NPRR562 creates new requirements for identifying and protecting against subsynchronous resonance (SSR) and clarifies responsibilities for affected entities. The ERCOT system has become more vulnerable to SSR with the introduction of series capacitors for voltage support. Without proper mitigation, SSR can quickly destroy resonating elements and resources, and lead to cascading outages.

“We built a grid that delivers power at 60 Hz,” said Woody Rickerson, ERCOT’s vice president of grid planning and operations. “That’s the synchronous heartbeat of the grid.”

Rickerson said series capacitors increase the risk of energy being exchanged at a frequency of less than 60 Hz.

The board also approved related changes to the Planning Guide, PGRR056, which accounts for potential SSR vulnerability in the transmission planning process, providing references and citations to the appropriate protocol sections related to SSR, and removing its definition from the guides.

Magness brought Fred Huang, manager of dynamic studies, before the board for special recognition, calling him instrumental in guiding NPRR562 through the PUC’s rulemaking process.

“[Huang] always ends up in the middle of something really hard and thorny we have to solve,” Magness said.

NPRR831, the only revision request to receive a separate vote, relates to private-use networks (PUNs) — networks connected to the ERCOT grid that contain load typically netted with internal generation and not directly metered by the ISO. The change updates market systems to calculate a net load value for each PUN that will be included in the load zone price for all markets, when the load is a net consumer from the grid.

Source Power & Gas’ John Werner encouraged ERCOT to find a short-term solution before NPRR831 goes into effect in October, saying revenue neutrality allocation has reached $50 million this year, five times the amount for the same period last year. The increase is a result of largely PUN loads creating point-to-point obligation payments without offsetting energy imbalance charges.

The consent agenda included five other NPRRs and two additional PGRRs:

NPRR796: An administrative revision specifying that character set validations are available within each Texas standard electronic transaction implementation guide.
NPRR820: Aligns the definition of an aggregate generation resource (AGR) with the Protocols, which allow a resource entity to register several generators as an AGR. Intermittent resources are not included.
NPRR824: Aligns Protocol language with NERC reliability standards for energy emergency alerts and real power balancing control performance.
NPRR827: Bars ERCOT from awarding point-to-point obligations in the day-ahead market when the corresponding clearing price is greater than the bid price for the PTP obligation by 25 cents/MWh or more. ERCOT said the change will prevent harm to market participants over “modeling issues that need to be resolved and any resolution will take many months to implement.” The ISO said the language change will not need to be reversed once the modeling issue is addressed because “any resolution of this issue must honor the fact the PTP obligation bid price reflects the maximum willingness to pay by the bidder.”
NPRR830: Revises the basis of ERCOT’s calculation of the four-coincident peak calculation (4-CP) to be consistent with NERC’s net-energy-for-load methodology. The proposed methodology uses metered net DC tie flows.
PGRR057: Aligns the Planning Guides with NERC Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing geomagnetic disturbance vulnerability assessments.
PGRR058: Clarifies specific generation to be included in the Planning Guide and the applicability requirements for proposed generation that must submit generation interconnection or change requests.

– Tom Kleckner

June 20, 2017

SPP SSC Briefs: June 14, 2017

Having agreed on a first potential interregional project with MISO, SPP is moving the 115-kV line in South Dakota through regional review.

SPP Interregional Coordinator Adam Bell told the Seams Steering Committee on June 14 that staff is working with the Economic Studies Working Group to develop a draft scope of the project.

The working group recommends using Futures 1 and 3 from the updated 2025 models in the 2017 Integrated Transmission Planning 10-Year Assessment to calculate the project’s one-year benefit-to-cost ratio. The group is also recommending using adjusted production cost and transmission outage mitigation as metrics in computing the ratio.

The SSC and ESWG will be the primary stakeholder groups directing the regional review, Bell said. They will make a recommendation to the Markets and Operations Policy Committee, with any approval from the Board of Directors coming in October.

The RTOs’ Interregional Planning Stakeholder Advisory Committee endorsed the $5.2 million project in April, and both stakeholder groups have since given their sign-off.

The project loops a Split Rock-Lawrence 115-kV circuit into Sioux Falls to relieve congestion on the Lawrence-Sioux Falls 115-kV line, shared by the Western Area Power Administration in SPP and Xcel Energy in MISO.

The project was the only one of seven joint recommendations to survive a coordinated system study conducted by the RTOs last year. Some of the projects failed to pass muster because of a $5 million threshold for interregional projects, a metric both RTOs are open to changing. (See 1 Project Recommended for MISO-SPP Coordinated Plan.)

SPP Continuing to Study Overlapping Charges

SPP staff continues to gather data on overlapping charges along the RTO’s seam with MISO, part of a coordinated effort by the two grid operators to determine the size of the problem they’re dealing with and whether agreements between transmission owners address transmission service.

Clint Savoy, senior interregional coordinator, said the issue arose with a MISO TO’s emergency tie agreement with an SPP member. The load was reliant on SPP facilities for service.

“We’re still reliant on the transmission owners and customers to tell us when these events occur,” Savoy said. “It would save the transmission customers money, without requiring system changes.”

Savoy said feedback from members has been slow so far, but staff is following up with those who have not yet responded.

The options before SPP and MISO include:

Revising their Tariffs and/or joint operating agreement to allow for after-the-fact reservations of transmission service for “abnormal” system conditions without unreserved-use penalties;
Revise the Tariffs and JOA to allow for after-the-fact accounting between transmission providers for abnormal system conditions without unreserved-use penalties;
Make no changes and still apply penalties when service is not prearranged; or
Revise Tariffs and/or market protocols to require settlement-location registration for any potential situations, or provide for a proxy for pricing congestion and losses.

Savoy said SPP’s Regional Tariff and Market working groups will take up the discussion and draft revision requests that might be necessary.

MISO Sends $2.15M in M2M Payments to SPP

Market-to-market payments from MISO to SPP in April dropped to almost half of those in March, with SPP collecting $2.15 million for congested flowgates between the two RTOs. MISO had sent its neighbor $3.98 million in March.

SPP has now collected $21.4 million from its neighbor since the two began the M2M process in March 2015.

Temporary flowgates racked up most of the payments ($1.38 million), binding for 435 hours. Permanent flowgates, which normally account for most the payments, were binding for 347 hours.

— Tom Kleckner

June 20, 2017

Huntoon: Microgrid Defense Misses the Point

By Steve Huntoon

Noblis continues to miss the basic point, which is readily apparent from two figures from its January 2017 report “Power Begins at Home: Assured Energy for U.S. Military Bases” (see graphic). The left figure is the status quo of individual building backup generators. The right figure is a microgrid.

microgrid military cybersecurity — Huntoon

As you can see, the microgrid adds exposure to military base distribution system problems because it is dependent on the distribution system. And distribution system problems cause the vast bulk of outages (87%).

This is not, as Noblis claims, a matter of “correcting” poorly maintained military base distribution systems, which Noblis would do by having the local utility assume responsibility for them.

Problems on local utilities’ own distribution systems cause about the same percentage of their customers’ outages (90%), as documented in footnote 5 of my column. Noblis does not address this.

The point is that most outages have nothing to do with poor maintenance, by military bases or by local utilities. Most outages are caused by severe weather, lightning, human error, unpredictable equipment failure, vehicle collisions, even metallic balloons and squirrels.

If local utilities had magic wands, they would wave them.

Noblis suggests undergrounding distribution systems to mitigate the added risk of microgrids, but it didn’t add the enormous cost of undergrounding to its microgrid costs.^[1] And it doesn’t consider that service restoration of an underground line outage typically takes much longer.

Speaking of cost, Noblis says its hypothetical microgrid cost under its natural gas “Case B” is close to the real-world cost of the microgrid at Marine Corps Air Station Miramar. I can’t reconcile this claim with the capital cost data Noblis presents in its Appendix C.2, which appear to be much lower. By the way, even if the Noblis data were right, its Case B is still uneconomic in the Northeast and Southeast regions that it modeled, and only economic in California.

And a few words about cybersecurity. My column did not suggest that no cyber protection exists for microgrids, simply that microgrids add cyber risk (and electromagnetic pulse risk) that does not exist with individual building backup generators.

The Department of Defense cyber protection that Noblis refers to is based on “limiting communication bandwidth within the network [microgrid].”^[2] The dilemma is that operating a microgrid of substantial size in parallel, in order to get the peak shaving, energy savings and demand response benefits that Noblis is counting on, cannot be done without communications links with the regional grid operator and the local utility. In other words, you can have (1) high cyber protection through isolation, or (2) benefits of parallel operation, but not both. Noblis eats the cake and has it too.

Finally, Noblis criticizes my reporting that the University of California, San Diego (UCSD) microgrid flunked its acid test in the Southwest Blackout of 2011. Noblis says my reference to that microgrid as “flagship” was “strange at best.” I didn’t make that up — just Google “UCSD microgrid flagship” (without quotation marks).

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel LLP.

(See STAKEHOLDER SOAPBOX – Noblis: Huntoon Microgrid Critique ‘Seriously Flawed’.)

The Edison Electric Institute estimates that undergrounding a distribution line costs up to $5 million per mile. http://www.eei.org/issuesandpolicy/electricreliability/undergrounding/documents/undergroundreport.pdf (page 31, Table 6.4). ↑
https://energy.gov/sites/prod/files/2016/03/f30/spiders_final_report.pdf (page 3-15). Microgrid Cyber Security Reference Architecture, which the DOD cyber protection follows (page 3-14), does not consider operational modes in which the microgrid is operating in parallel with the rest of the grid. http://prod.sandia.gov/techlib/access-control.cgi/2013/135472.pdf (page 23). ↑

June 20, 2017

PJM Making Moves to Preserve Market Integrity

By Rory D. Sweeney

For some time, PJM has found itself in a no-win situation, pitting stakeholders valuing market consistency against those seeking flexibility to integrate changing ideas and technologies.

From technological advancements that have reduced demand, to the shale gas boom that has upended the supply stack, to governmental actions that have artificially buoyed preferred technologies, what’s an RTO to do?

“Increasingly, public policies seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes,” PJM said in an explanatory document released last week. “The most recent iteration of state policies has involved explicit, legislatively driven subsidies for specific generating units. These types of subsidies can suppress wholesale electricity market prices and threaten these markets’ basic design mission.”

But through that document and three supporting papers, PJM believes it has found a way forward. The RTO published the document along with the last two of three working papers that each focus on addressing different aspects of the issue.

The first, published the same day as a May FERC technical conference analyzing the viability of energy markets, offered guidelines for how states could work with PJM to develop carbon pricing rules that integrate with existing market structures. (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)

The second, published last week as an update of a proposal PJM floated last year, outlines a two-phase capacity auction that would allow subsidized resources to be counted as available reserves without influencing the clearing price. (See PJM’s Grid 20/20 Ponders Mixing Public Policy, Competitive Markets.)

Also published last week was a third paper containing ideas initially advanced in PJM’s response to its Independent Market Monitor’s 2016 State of the Market report. In it, the RTO proposes tweaks to its energy market design to address complaints that market factors — both naturally developing and artificially introduced — have improperly depressed clearing prices so that true real-time costs aren’t being accurately reflected. The grid operator argues that its price-setting logic should be revised to allow inflexible units to set LMPs. (See PJM Differs with Monitor in State of the Market Response.)

“Since the inception of competitive wholesale electricity markets, the industry has evolved significantly and in ways that could not have been fully anticipated,” the document said. “Technological disruptions … have altered the economics of electricity supply, creating new opportunities and challenges. … These shifts in economic trends and market dynamics could lead to an unintended bias in the energy markets favoring lower capital cost resources … [putting] financial stress on all units, but particularly large units with high capital costs.”

The proposals face an uphill battle for acceptance. Stakeholders have criticized PJM for filing some of the ideas with FERC as additional testimony during the technical conference. The Monitor opposes the proposed changes to the LMP-setting logic.

Market participants have also expressed concerns with the RTO’s two-phase capacity-auction proposal. And carbon pricing was a tough sell long before President Trump set out to eliminate his predecessor’s signature Clean Power Plan. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)

PJM acknowledges the work ahead. The capacity proposal, it said, “likely will be evaluated with other potential solutions” by the Capacity Constructs/Public Policy Senior Task Force, which has been meeting regularly since January and remains mired in foundational discussions on the basic goals of a capacity construct. (See PJM Capacity Task Force Debates the Value of Price Transparency.)

The other proposals haven’t found a home for discussion yet, but the RTO is confident something must be done.

“I certainly think a do-nothing approach going forward puts the goals of the markets in general at risk,” Stu Bresler, PJM’s senior vice president of operations and markets, said at PJM’s Grid 20/20 conference on the issue last August. “The risk of a do-nothing approach is a detrimental effect on the long-term price signal.”

June 20, 2017

SOAPBOX – Huntoon Microgrid Critique ‘Seriously Flawed’

By Jeffrey Marqusee

Steve Huntoon’s March 13 column “Microgrid Kool-Aid and National Security” reviews the Noblis report “Power Begins at Home: Assured Energy for U.S. Military Bases” and raised a number of issues that he claims invalidate the study’s conclusions. Huntoon’s claims and conclusions are seriously flawed.

Huntoon cites a recent Government Accountability Office report that found outages can be attributed to on-base problems as opposed to the utility. He states that outages attributed to on-base issues cannot be solved: “if they were easily avoided, they would be.” From this statement he concludes, incorrectly, microgrids cannot be the solution.

Our report specifically acknowledges that problems with on-base distribution systems must be corrected prior to using a microgrid and in most cases this can easily be accomplished. Currently, some outages on military bases are completely due to the utilities that serve the base (Fort Irwin), while others are due to on-base infrastructure issues (Camp Lejeune). Fixing these on-base problems is well understood and routinely done. Simple activities such as tree trimming, routine maintenance and, when needed, undergrounding of distribution systems can and do reduce the issue to near zero. Fort Belvoir has demonstrated this through these actions over the last several years.

The main reason it has not been done at all bases is well recognized at the Defense Department and is the driver for utility privatization. Maintenance of on-base utility systems has been underfunded for decades. Fort Belvoir is a perfect example. Upon privatizing the on-base utilities, the frequency of outages attributed to on-base issues began to rapidly decline to near zero.

Huntoon argues that microgrids place military installations at risk to cyber threats. He implies that this risk should not be taken.

As the report explicitly states, cyber risks are real and must be addressed, but this was not the focus of our study. If you believe that cyber risks should be always avoided, then you cannot have advanced meters, smart buildings or network anything (including weapon systems). You network things because it buys performance advantages, as in the case of microgrids, and if you own the network you can manage that risk. Huntoon seems unaware that cyber protection for microgrids exists. Cybersecurity solutions for microgrids have been demonstrated on bases by the government’s Environmental Security Technology Certification Program and its Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS) program.

Huntoon says, “please note one other glaring oversight in the study. This one involves the estimated cost of microgrids.” He claims the study’s estimated costs are grossly wrong by comparing numbers he incorrectly quotes from the report with recent costs for a project at Marine Corps Air Station Miramar.

His comparison of our estimates and a real-world example at Miramar are grossly in error. He quotes our number for the capital costs of an all diesel generator system rather than the costs for one that is half natural gas and half diesel like Miramar. The numbers he should have quoted from the report, which are relevant to Miramar, are twice the numbers he does quote. In addition, he ignored the costs of two microgrid control stations as well as other upgrades. In fact, our cost estimates, constructed prior to the award of the Miramar contract, when compared apples to apples is within 10% of the actual costs.

In the conclusion, Huntoon states, “And speaking of fact, the nation’s ‘flagship’ microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.” He implies that microgrids don’t work.

microgrids military bases noblis — UC San Diego Microgrid | *UC San Diego*

No one in the microgrid technical community believes that the U.C. San Diego microgrid is the “flagship” example. Using a decade-old, university-based microgrid as an example is strange at best. Dozens of microgrids have been demonstrated in recent years. They all operate as designed during outages and provide assured power. For example, the White Oak microgrid, which is described in the report, has maintained power during dozens of outages, never experienced a failure and is saving money each year.

Jeffrey Marqusee, Ph.D., is chief scientist for Noblis, a nonprofit science, technology and strategy organization whose clients include many federal government agencies.

(See Huntoon: Microgrid Defense Misses the Point.)

June 20, 2017

UPDATE: California Heat Wave Prompts CAISO Flex Alert

CAISO on Monday called on consumers to voluntarily conserve energy this week as scorching heat drove up electricity usage and caused outages in Pacific Gas and Electric’s service territory.

The ISO issued a “flex alert” effective 2 to 9 p.m. on Tuesday and Wednesday, with peak load expected to break 47,000 MW both days in the face of triple-digit temperatures. The alerts are issued when the grid is “under stress” from generation or transmission outages, or persistently high temperatures, the ISO said.

This week’s expected peaks would be more than 90% of CAISO’s all-time peak demand of 50,270 MW, set on July 24, 2006.

By late Monday, the ISO forecast that the day’s peak demand would hit about 44,600 MW, well short of an earlier forecast of 46,500 MW.

Temperatures soared up to 110 degrees in California’s interior, the most intense heat wave to hit the state since the summer of 2013. Multiple days of extreme heat are stressing equipment and causing some outages. PG&E still had 4,200 customers without power as of Monday morning, with about 189,000 customers initially affected.

“This is a heat wave, and we have got all our generation that we can make available made available to us,” CAISO spokesman Steven Greenlee said during a media call held jointly with PG&E.

An extended period of very hot weather is expected across the interior portions of southwest California through the middle of the week, and temperatures could reach 112 degrees in parts of the state, the National Weather Service said as it issued a heat advisory.

– Jason Fordney

June 20, 2017

Offshore Wind Developers Ponder Tx Options

By Michael Kuser

BOSTON — Massachusetts faces a big question in its plan to add 1,600 MW of offshore wind by 2027: What’s the best way to get the power to shore?

The state, which is expected to issue a request for proposals by the end of the month for at least 400 MW, will ask the three winners of offshore wind leases to propose both underwater transmission cables for each of their projects and a single trunk line that would serve all three. Developers also will have to choose between high-voltage AC or DC lines.

Panel left to right: Stephens, Conant, Calviou and Hindbo | © *RTO Insider*

The stakes, as a panel told Raab Associates’ 154th New England Electricity Restructuring Roundtable on Friday, are high.

A multibillion-dollar offshore wind farm can be stranded for six months because of a single cable fault. However, developers can reduce their risk through contracts that provide compensation for transmission failures, said Søren Hindbo, senior director of electrical systems for DONG Energy. In addition, interlink cables among substations can allow electricity to be sent ashore even when an export cable fails, he said.

Denmark-based DONG — which has 26 years of offshore wind experience, with 21 European wind farms in operation and seven under construction — was one of three companies to win leases off of Massachusetts from the U.S. Bureau of Ocean Energy Management. Deepwater Wind and Vineyard Wind (formerly OffshoreMW) also won.

iso-ne transmission offshore wind — | *National Grid*

Hindbo described the contracts used in Germany, France, the Netherlands and Denmark, which provide wind developers compensation if there is a transmission problem. “You measure the wind speed on the wind farm and get compensated according to that, if for instance the connection is delayed or faulty. And that’s very important, because who wants to invest in something and have your billions put up there and no chance of getting anything back because you haven’t got an export connection?”

DONG expects two to three export cable faults per 100 km per 20 years, so having interlinks to provide alternative routes for delivering power is important, he said. “One benefit is you don’t need diesels [for] a black start; also if you are delayed, which often happens … you are still in the game,” Hindbo said.

In Europe, developers have found HVDC lines more cost effective for the most distant wind farms and AC better for those closer to shore, with a break-even point between 100 and 200 km (about 62 to 124 miles).

The export cable represents up to 60% of the total cost in an HVAC system. The total percentage is somewhat lower with a HVDC system, Hindbo said, though the total capital expenditure is higher. “The export cable,” he said. “It’s the weakest and the most expensive part.”

Backbone or Alternatives?

Mike Calviou, senior vice president at National Grid USA, said the most cost-effective approach is a “coordinated and expandable” plan that accommodates future offshore resources, citing research showing it can reduce costs by 8 to 16%. National Grid connected the first offshore wind farm in the U.S. to the grid, the 30-MW Block Island project off Rhode Island.

“We believe coordination does provide a range of benefits: fewer cables; you get the economies of scale; the permitting complexity can actually be significant. There are certainly, we believe, some environmental and safety benefits,” he said. “And particularly the expandability: When you know you are going to be doing more offshore wind … you can actually design for future expansion.”

Anbaric’s Stephen Conant said the RFP unwisely excludes transmission developers such as his company from participating in the design of a solution: They aren’t permitted to respond to the RFP except in partnership with one of the three wind developers/lease holders.

“We think competition is good for the industry,” Conant said. “Putting generators in the transmission business seemed a little odd in the RFP. We have a system here that we separate transmission and generation by having a common transmission system [onshore]. That then allows … those generators to bid competitively into the market.”

The RFP could give market power to the three leaseholders, he said.

“The way the construct is now, essentially if they pick one [bidder], then the first one in … their tendency is going to be to sort of lean towards the expansion of their [initial] 400 or 800 [MW]. So you’ve essentially gotten a little market power that exists as a result of not letting others into the field.”

Anbaric, which was among a group of entities that built the 660-MW Neptune HVDC cable linking PJM to Long Island Power Authority and the 660-MW Hudson project connecting PJM to New York City, is also developing the Vermont Green Line, a 400-MW project to deliver power from upstate New York into the New England grid.

Equal Treatment

Erich Stephens, CEO of Vineyard Wind, highlighted the risk of separating the transmission and generation projects. “If you separate as a matter of policy who builds the generation from who builds the cable, you basically have two projects going forward at the same time,” he said. “Inevitably those projects are not going to be finished at the same time … and that means you’re going to have a very expensive asset sitting offshore that’s not earning the revenue that it should.”

Vineyard Wind was already working with Copenhagen Infrastructure Partners on its offshore wind projects before earlier this year selling a 50% stake to Avangrid Renewables to bid in the Massachusetts RFP.

June 19, 2017

PJM MRC/MC Preview: June 22, 2017

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:40)

Members will be asked to endorse the following proposed manual changes:

A. Manual 14A: Generation and Transmission Interconnection Process and the Tariff. Revisions developed to the manual and the Tariff to allocate reinforcement costs of less than $5 million to all projects in a queue that add load to the violation causing the need for the reinforcement. Also removes alternate queue screening, allowing projects to be evaluated for impacts once the point of interconnection has been established. (See “Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues,” PJM Planning and Tx Expansion Advisory Committees Briefs.)

B. Manual 14C: Generation and Transmission Interconnection Facility Construction. Revisions developed to incorporate the minimum engineering design standards developed by the Designated Entity Design Standards Taskforce for competitively solicited projects for transmission lines, substations and “system protection and control design and coordination.” (See “Competitive Planning Components Endorsed; Pieces Remain,” PJM Planning & Tx Expansion Advisory Committees Briefs.)

C. Manual 14F: Competitive Planning Process. A new manual that consolidates PJM policies implementing FERC Order 1000. (See “Competitive Planning Components Endorsed; Pieces Remain,” PJM Planning & Tx Expansion Advisory Committees Briefs.)

D. Manual 20: PJM Resource Adequacy Analysis. Revisions developed to address changes to modeling of zonal and global locational deliverability areas for capacity emergency transfer objective calculations. (See “ISO-NE out of this ‘World,’ According to PJM Reserve Requirement Study,” PJM Planning Committee/TEAC Briefs.)

E. Manual 28: Operating Agreement Accounting. Revisions conform with FERC order in docket ER16-121-001 requiring allocation of balancing congestion and real-time market-to-market payments to real-time load plus exports on a pro rata basis RTO-wide. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix and “FTR Revisions Continue Forward,” PJM Market Implementation Committee Briefs.)

F. Manual 39: Nuclear Plant Interface Coordination. Revisions clarify that nuclear operators must communicate any limiting conditions affecting interface requirements following notification of a grid-side event. The revisions, which include limits on the operability of offsite power sources, are intended to ensure that PJM and the transmission owner local control center have situational awareness of nuclear plant conditions.

3. Pseudo-Tie Pro Forma (9:40-10:15)

Members will be asked to endorse proposed pro forma agreements, along with corresponding Tariff and Operating Agreement revisions. A draft dynamic schedule agreement will also be presented, but it will be voted on at a future meeting. (See “Pseudo-Tie Discussion Postponed to Continue Negotiations with MISO,” PJM Markets and Reliability Committee Briefs.)

4. Regulation Market Issues Senior Task Force (RMISTF) (10:15-10:45)

Members will be asked to endorse the regulation market changes proposed by PJM and the Independent Market Monitor and endorsed by the Regulation Market Issues Senior Task Force. The changes affect benefit factors, performance scoring and settlements, and implements a 24-month transition plan. (See “Stakeholders Defer Vote on Regulation Revisions,” PJM Markets and Reliability Committee Briefs.)

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to endorse:

B. Operating Agreement and Tariff revisions requiring solar generators to provide meteorological and forced outage data — previously only required from wind generators — in compliance with FERC Order 764. (See “Solar Forecast Is Coming,” PJM Planning and Tx Expansion Advisory Committees Briefs.)

C. Operating Agreement and Tariff revisions create a method for compensating pseudo-tied generators and dynamic schedules, which are not eligible to submit meter correction data, as permitted for internal generators and tie lines. (See “Meter Correction Initiative OK’d,” PJM Market Implementation Committee Briefs.)

D. Operating Agreement and Tariff revisions related to annual revenue requirements for new black start units. Sets deadlines for the submittal and review of new black start units’ capital, variable and fuel storage costs; policies for allocating costs to network service customers and point-to-point reservations. (See “New Black Start Units Will Have New Annual Revenue Requirements,” PJM Markets and Reliability Committee Briefs.)

1. Energy Market Uplift Senior Task Force (1:25-1:45)

Members will be asked to endorse proposed Tariff and Operating Agreement revisions intended to preserve the benefits of virtual trading while eliminating opportunities for such transactions to profit from the market without providing benefits. Increment offers (INCs) and decrement bids (DECs) are permitted at locations where the settlement of physical energy occurs plus trading hubs; up-to-congestion transactions are permitted at hubs, zones and interfaces. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)

– Rory D. Sweeney

June 19, 2017

Scorecard Uncovers Three MISO IT Issues

By Amanda Durish Cook

CARMEL, Ind. — A quarterly IT scorecard audit has uncovered three technology-related issues for MISO staff to address.

In light of the audit, MISO will review a nine-hour website outage, continue to ensure that ex-employees don’t have system access 24 hours beyond their departure and commit more time to building its own settlement software system, the Technology Committee of the Board of Directors learned during a June 15 conference call.

MISO information technology IT scorecard — MISO’s Carmel. Indiana Control Room in 2013 | *MISO*

MISO Technology Executive Kevin Caringer said the RTO will need an additional $390,000 to build its own settlement system software because staff were in some cases required to reverse-engineer the existing system to find original settlement software code.

Director Baljit Dail said the RTO should have all software code already documented as standard practice. “It gets into a very scary place where we want to change the code but we don’t know what the original code is or what it does,” he said.

Caringer said MISO had a majority of the original code and will run the old and new code in parallel for a few days until determining the success of the RTO-built system. If the new code fails, MISO will revert to the old code.

“We have done this in the past in the RTO as well for other major changes. It’s something we’re familiar with,” Caringer said.

He also noted that MISO will use the software to implement five-minute real-time settlements, which are expected in January.

The RTO meanwhile continues to strive to terminate the system access of former employees within 24 hours, Chief Information Officer Keri Glitch said.

“We are moving on a positive trajectory, and I have confidence we’ll continue moving forward,” Glitch said.

MISO has consistently scored near 100% in timely access terminations since February, up from a low of 42% in November. The RTO said access termination issues can arise when a third-party vendor fails to notify it when a contractor leaves.

Dail asked if MISO has any recourse if a vendor fails to alert it of exiting contractors.

Glitch said the RTO is developing new contract language setting out a procedure for vendors to notify it and terminate access.

The RTO is also reviewing a nine-hour public website outage that occurred from 4 p.m. to 1 a.m. on a Friday evening in March, after a physical network device failed and an employee exacerbated the situation by improperly configuring a switch-over to a backup device — leading to the outage.

“It appeared to be a human error,” Glitch said, adding that hardware components on critical network switches rarely fail.

Glitch said MISO is conducting a review of overall network design and failover capabilities when third-party vendors are involved.

June 19, 2017

Questions to FERC Nominees Reflect Democrats’ Wish List

By Michael Brooks

President Trump’s nominees to FERC gave nearly identical, boilerplate answers to senators’ written questions on issues ranging from hydroelectric project licensing to natural gas infrastructure following their confirmation hearing last month.

The questions, mostly from Democratic and left-leaning independent senators, provide more insight into a party grappling with being in the minority under a presidential administration hostile to environmental issues rather than the nominees themselves.

ferc trump chatterjee powelson — Powelson | © *RTO Insider*

Robert Powelson, a Pennsylvania Public Utility Commissioner, and Neil Chatterjee, senior energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), toed the FERC line, declining to answer questions about specific cases pending before the commission. The two, who were each approved 20-3 by the Energy and Natural Resources (ENR) Committee on June 6, are awaiting a confirmation vote by the full Senate. (See FERC Nominees Easily Advance to Full Senate.) No vote has been scheduled as of last week.

They pointed to recent technical conferences when asked about state energy policies and barriers to participation in the wholesale markets to energy storage, saying they were “eager” or “looking forward” to reviewing comments the commission has received.

They also provided similar answers to questions about Order 1000, about which nearly every senator who submitted written questions asked.

Senators expressed concern that there were still problems with the interregional transmission process. Sen. Joe Manchin (D-W.Va.) in particular quoted PJM CEO Andy Ott and SPP CEO Nick Brown’s criticisms of Order 1000 at the RTO Insider/SAS ISO Summit in March. (See PJM, SPP Chiefs Share Frustration with Order 1000.)

Both nominees said they were supportive of the order and pledged to carefully consider stakeholder feedback on last year’s technical conference. “I am a strong advocate for interregional transmission planning and, in my view, the commission’s implementation Order No. 1000 is a work in progress,” Powelson said.

The nominees also asserted that changes to how the commission administers the Federal Power Act, the Natural Gas Act and the Public Utility Regulatory Policies Act should come from Congress, not FERC.

Sen. Maria Cantwell (D-Wash.), for example, noted that while the electric industry is subject to mandatory cybersecurity standards, gas pipelines are only subject to voluntary guidelines issued by the Transportation Security Administration. She asked the nominees whether they agreed that there should be mandatory standards for pipelines.

“I defer to Congress and the Transportation Security Administration (TSA) as to the adequacy of TSA’s natural gas pipeline cybersecurity program,” Chatterjee answered. “Congress has granted TSA authority to establish mandatory cybersecurity regulations for natural gas pipelines.”

“Congress and the TSA are in the best position to evaluate TSA’s current natural gas pipeline security authority to determine if natural gas pipelines should be subject to additional or mandatory cybersecurity standards,” was Powelson’s answer.

Senators also asked questions particular to their individual states. Sen. Al Franken (D-Minn.) asked about problems with coal transportation by railway in Minnesota — another TSA issue, the nominees said.

But Sen. Tammy Duckworth (D-Ill.) asked about states served by multiple RTOs — which include Illinois. “States that are split into two RTOs are encountering issues where generating resources have been separated from the loads that they were built or contracted to serve,” she said. “How should proximity to resources, actual power flows and pre-existing transmission rights be considered in RTO modeling?”

Both nominees said they could not answer, as it was a question pending before the commission.

Environment and Climate Change

Powelson and Chatterjee’s deferral to Congress extended to questions about environmental impacts, climate change and increasing the use of clean energy resources, subjects about which every Democratic and liberal senator asked.

Sen. Bernie Sanders (I-Vt.), one of the three ENR members to vote against the nominees earlier this month, asked the nominees 52 questions — far more than any other senator — many of them related to the environment. Four questions asked in different ways whether the nominees accepted prevailing climate science.

Powelson and Chatterjee repeated their answers from their confirmation hearing that they understood climate change was real — and not a “hoax,” as Trump has claimed. (See No Fireworks for FERC Nominees at Senate Hearing.)

But they said it was not FERC’s place to regulate it or attempt to decarbonize the nation’s energy mix.

“Any policy to mitigate carbon emissions should originate in Congress; it should not be designed at FERC,” Chatterjee said. “Addressing climate change will require policy changes that the public accepts, and maintaining and enhancing affordability and reliability is vital to gaining that public acceptance. Should I be fortunate enough to be confirmed, my role as a FERC commissioner would be to ensure that any such policy not have a deleterious impact on reliability and affordability of our energy supply.”

“My understanding is that FERC’s policies are resource- and fuel-neutral,” Powelson said. “The commission relies on competitive markets to provide just and reasonable rates and reliable service for consumers, and to send appropriate investment signals for developers. … If confirmed, I will refrain from picking ‘winners and losers’ in the energy marketplace, as that is not FERC’s role.”

Questions by Sanders and others indicated their desire for FERC to slow down its approvals of gas pipelines. They asked the nominees if they agreed with former Chairman Norman Bay’s call for a review of the cumulative environmental impacts from Marcellus and Utica shale drilling. (See Bay Calls for Review of Marcellus, Utica Shale Development.)

While Chatterjee’s answer was anodyne — committing to working with his colleagues in reviewing commission policies — Powelson was more forceful in his answer.

“I respectfully disagree with that recommendation,” he said. “As a Pennsylvania state regulator … I believe that this issue would be better addressed at the state level. State environmental regulators and state public utility commissions are closer to the issues of shale gas development and are better equipped than the federal government to undertake such an assessment.”

Public Participation

Senators also expressed concerns about potential barriers to public participation in FERC’s processes.

“FERC is incredibly complicated, and the barrier to entry for someone to simply understand FERC proceedings, much less to participate, is extremely high,” Sanders said. “Stakeholders with considerable financial resources can participate, but everyone else is effectively excluded.”

Both Sanders and Franken asked about legislation that would create an Office of Public Participation and Consumer Advocacy at the commission, an issue earlier raised by public interest group Public Citizen. (See Public Interest Groups Cry Foul over Technical Conference, RTO Transparency.)

Both nominees wrote that they would “work with my colleagues to identify further steps that FERC could take to make its proceedings and processes more accessible to the public.”

But Powelson also said, “I do not believe that the creation of such an office at FERC is necessary. In my view, the public comment process at FERC provides all interested parties with the ability to participate in the process and express their positions on issues.”

Duckworth also spoke up for public interest groups, saying they believe they have “an extremely limited voice in RTO stakeholder discussions, and RTO actions taken behind closed doors seem to be condoned by FERC.”

Last week, Virginia Democratic Sens. Tim Kaine and Mark Warner introduced legislation that among other provisions would mandate public comment meetings in every locality in the path of a proposed interstate gas pipeline. The bill is in response to complaints in the state about the limited opportunity for the public to provide feedback.

Republican Rep. Morgan Griffith, also from Virginia and a member of the House Energy and Commerce Committee, introduced a similar bill in the House.