Page 1298 – RTO Insider

June 20, 2017

Nuclear Subsidy Debate Touches Down in New England

By Michael Kuser

BOSTON — When Connecticut Consumer Counsel Elin Swanson Katz decided to support a controversial bill to provide state financial support for Dominion Energy’s Millstone nuclear plant, it strained relationships.

“In fact, some of our closest allies barely spoke to me during the [legislative] session,” she said.

New England Restructuring Roundtable nuclear subsidy — Katz | © *RTO Insider*

Katz’s anecdote, related to an audience at the 154th New England Electricity Restructuring Roundtable on Friday, was one example of the schisms that have arisen in recent years as many former nuclear power opponents have traded their fear of meltdowns and nuclear waste for appreciation of the plants’ ability to produce large amounts of power with no carbon emissions.

Similarly, Katz and other consumer advocates have had to consider whether losing a plant such as Millstone would be more expensive to ratepayers than any subsidies that would ensure its continued operation.

Opening a panel discussion featuring partisans on all sides of the nuclear debate, moderator Jonathan Raab observed: “The environmental community, like the consumer advocacy community, is not of one mind on the role of nukes in our society.”

Low natural gas prices, flat demand growth and growing renewable generation have squeezed the finances of many nuclear plants, leading policymakers in New York and Illinois to approve subsidies in the form of zero-emission credits (ZECs). Officials in New Jersey, Ohio and other states are considering similar measures despite challenges to the Illinois and New York ZECs in court and before FERC. (See Exelon Encouraged by Perry’s Memo, Thinks ZECs Will Hold Up.)

Blind Markets

Matthew Crozat of the Nuclear Energy Institute told the audience that states are stepping in to save nuclear plants because wholesale electric markets have failed to price carbon emissions.

Crozat identified several plants that have closed or are slated for decommissioning by 2025. While some closed because of mechanical issues, “market forces claimed well operating plants,” Crozat said. “They just could not see a way to recover their costs in the future, and that includes Vermont Yankee here in New England.”

A combination of market forces and public policy pressures could result in the retirement of eight nuclear plants in the coming decade, for a total of about 12 GW of capacity, or some 60 million tons of CO₂ avoided annually, Crozat said.

“When Vermont Yankee closed [in 2014], all of its generation was replaced by natural gas,” Crozat said. “This was not a surprise; it was the next available unit in the system. I think it was the first time in 15 years that carbon emissions from New England’s power sector had gone up, and we saw the same pattern in California as well” following the loss of San Onofre in 2013.

Controversy in Connecticut

Earlier this month, the Connecticut General Assembly failed to pass a bill, S.B. 106, that would have allowed the 2,111-MW Millstone plant to bid into the state procurement process.

Opponents of the bill said it represented a burden on state ratepayers and an unnecessary handout to a power plant that had not been proven to be unprofitable. John Shelk, CEO of the Electric Power Supply Association, who also spoke at the Roundtable, said Millstone is likely the most profitable nuclear plant on the East Coast. (See Millstone No Dead Weight for Dominion, Says Opponents’ Study.)

Katz, however, said she was concerned about what the loss of the plant — which produces half of the electricity consumed in the state — would mean to the ratepayers she represents. “It would have provided a potential opportunity, in my view, to save electric ratepayers money, and the procurement process would have allowed me to oppose a potential contract if it did not do so,” Katz told RTO Insider after the conference. “We did not think Millstone was at serious risk of closing, so we did not look at the proposed legislation through that lens.”

If Millstone retired, the region would undoubtedly have to secure new generating capacity, which would result in higher capacity costs, she said. “Connecticut and the region would presumably increase its reliance on natural gas and we would need more pipeline infrastructure to avoid infrastructure constraints. Connecticut, as you know, is at the end of the pipeline, and in cold winters that creates real problems for us.”

In addition, Millstone’s retirement “would likely see New England’s electric sector emissions increase by as much as 8 million tons, or approximately 27%,” Katz said. “Closure would make compliance with our state’s Global Warming Solutions Act challenging, as it requires that we must achieve greenhouse gas emissions 10% below 1990 levels by 2020 on an economy-wide basis.”

Not So Fast

In considering the future of nuclear power in New England, you couldn’t get more concise than a recent paper by the Rocky Mountain Institute titled “What the grid needs is a symphony, not a shouting match,” Shelk said.

“We are the lead plaintiff contesting the Illinois ZECs,” he said. “We’re also part of the litigation in New York, and we were working at the state level. … Why do we care? It’s very simple. These proposals single out nuclear, and only nuclear, for substantial state subsidies. It doesn’t extinguish the risk that nuclear plants face; it merely shifts it to the rest of us and our customers.”

New England Electricity Restructuring Roundtable nuclear subsidy — Raab | © *RTO Insider*

EPSA has been joined in the Illinois litigation by PJM’s Independent Market Monitor, who has called ZECs a “contagion” that undermines the markets.

Shelk said that at current PJM prices of about $30/MWh, the Illinois ZECs are worth about $11.50/MWh.

“Those of us that are competing against each other, one set of competitors gets $30, and somebody else gets almost a 50% premium to the market,” he said. “And it’s unrelated to carbon. If we take steps to switch … from coal to gas or within gas to more efficient gas turbines — which are coming on the market very rapidly — we get zero for that attribute. And as you all know, a ton [of emissions] avoided is a ton avoided. So nuclear and only nuclear power, and only certain plants in PJM and New York, would get that additional price.”

Next Generation

Armond Cohen, executive director of the Clean Air Task Force, began his career as a lawyer fighting nuclear power, but he has now come to see the environmental value of nuclear power in improving air quality in New England.

“As you can see in the march towards a zero-carbon grid, nuclear contributes something … quite significant when compared to some of the other options,” Cohen said.

All the renewable energy being developed “adds up, but the point is, in scale, it’s still a little bit less than the existing nuclear,” he said. “And I’m not arguing this as an either/or; quite the contrary. I’m arguing that we should maintain the nuclear base and build on top of it. Over the longer term, the management of a very high weather-dependent system becomes complicated.”

Cohen said he has hopes for next-generation nuclear power technology, which promises to reduce costs by using coolants that remain stable at higher temperatures. He estimated costs can be achieved at about $40 to $60/MWh for the new designs.

“Those [new coolants] are things like molten salts to sodium helium and can operate at atmospheric pressure,” he said. “That reduces the need for pressurized containment, and that’s about two-thirds of the plant’s steel and concrete at Seabrook and Millstone. If you don’t have to keep water under very high pressure and containment, you vastly reduce the size and complexity of construction. That allows you to go to a factory production model with faster and more predictable completion times.”

Several developers in the U.S. have designs of next-generation nuclear power plants “at the paper stage” and foresee operational plants by 2030, Cohen said. He lamented that the U.S. has fallen behind China, which hopes to bring its first such plant online next year.

Restructuring Legalities

Ari Peskoe, senior fellow in electricity law at Harvard Law School, outlined the issues that contributed to the nuclear industry’s problems and the legal hurdles ZECs may have to clear.

“Restructuring removed generation from the rate base and severed the state’s planning authority, its environmental regulatory authority, from how the plant was actually going to earn its money,” Peskoe said. “That’s critical, because if at the end of the day the plant can’t earn its money, it’s not going to get built.”

Peskoe summarized three legal claims about ZECs at issue in federal court: That the states are regulating wholesale rates and thus intruding on FERC’s exclusive jurisdiction (field pre-emption); that they “stand as an obstacle” to FERC’s regulation of just and reasonable rates (conflict pre-emption); and that they favor in-state businesses in violation of the Constitution’s dormant Commerce Clause.

Rulings on the ZECs, Peskoe said, could have broader implications. “If ZECs are pre-empted, are [renewable portfolio standards] or the Regional Greenhouse Gas Initiative next?” And if a nuclear PPA is rejected, he asked, will Massachusetts’ procurements for hydro and offshore wind be at risk?

June 20, 2017

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

NERC: Despite Solid 2016, Grid Threats Remain

By Rory D. Sweeney

The North American grid was very reliable in 2016, but threats are increasing and restoration from a total system collapse could prove time-consuming, two recent nationwide studies found.

NERC last week released its annual analysis of the grid’s performance, which found that while 2016 ranked as the second-most reliable year on record, threats to the system — particularly on the cybersecurity front — are on the rise.

The revelation adds weight to a recent joint FERC/NERC report that found that recovery of the bulk power system (BPS) from a blackout could be a lengthy and resource-consuming process if supervisory control and data acquisition (SCADA) and energy management system (EMS) functionality are also lost. The report was based on responses from eight industry participants who provided information for the study.

The system’s cumulative severity risk index (SRI) for 2016 is second only to 2011 since the metric began being tracked in 2008. Breaking it down by each BPS component, unplanned generation unavailability accounted for the vast majority of cumulative SRI, which the report said is typical. Transmission loss made up about a fifth of the total, and load loss was relatively minimal.

“No single component shows a significant step change for any given day,” the NERC report says. “The performance within each segment proves to be very stable.”

James Merlo, NERC’s senior director of reliability risk management, said that 2016 was the second consecutive year in which no daily SRI broke the top 10 most severe days on record, despite days with severe weather. This indicated that the BPS is becoming increasingly resilient to severe conditions, he said.

Merlo reported that overall transmission outage severity was reduced year over year. For the second consecutive year, there were no Category 4 or 5 events — the most severe — and only two Category 3 events.

Still, outages caused by human error last year increased to 2014 levels after falling in 2015.

“While no increase in outage severity was discovered, human error remains a major contributor to transmission outage severity and will remain an area of focus,” the report said.

However, the misoperation rate continued a four-year trend of decline across North America. Misoperation events have the highest correlation with the most severe outages.

Frequency response, what Merlo called the “heartbeat of the grid,” is “looking good,” he said. It remains flat or improving across the continent. He said frequency response becomes “different” but not necessarily harder with the influx of intermittent resources on the system.

He also reported that no load was lost to physical or cybersecurity attacks but noted that such attacks are increasing.

“It’s a positive finding, but I think we all know that we’re going to have to give our attention in this area based on the risk increasing every day,” he said.

The report highlights National Institute of Standards and Technology data that indicate high-severity cybersecurity vulnerabilities are consistently increasing. However, vulnerabilities increased 23%, while incidents increased 38%.

“Vulnerabilities are increasingly being successfully exploited, [which] reinforces the need for organizations to continue to enhance their cybersecurity capabilities,” the report says.

The threat was further accentuated in the joint report from FERC and NERC, which found that all participants would remain capable of executing their restoration plans without SCADA/EMS availability by leveraging redundancies. However, the process would be more complicated, take more time, require more resources and rely much more on “interpersonal” communications.

“Participants indicated that system restoration steps [that] involve additional communications and coordination with multiple personnel, such as load pick-up, will be more labor-intensive in the absence of SCADA or EMS,” the report said.

The report recommends utilities ensure the effectiveness of backup communications systems and incorporate that into emergency training, including determining the manpower and tools necessary to collect information and maintain operational awareness without SCADA.

“Participants expected that dependency on interpersonal communications would significantly increase in performing system restoration in the absence of SCADA, and that any unavailability of interpersonal communications would further hamper system restoration,” the report said.

It also recommended considering the shelf life of onsite fuel for backup generators and backup area control error applications.

Participants reported that their emergency procedures were flexible and robust enough to handle a wide range of changing circumstances. All plans involve development of multiple restoration paths and islands.

“If a SCADA system(s) is still unavailable as system restoration progresses, the participants may adjust their restoration strategy accordingly, e.g., restore areas within the reliability coordinator footprint but remain operating as separate islands within the reliability area, holding off synchronizing to form a larger island and/or interconnecting with the rest of the interconnection, thereby reducing the risk of an outage to a larger restored area,” the report said.

In the event of a cyber event that disables SCADA or EMS, participants indicated it would be more reliable to remain islanded “until associated risks are alleviated” in order to avoid repeated widespread blackout.

The increased reliance on interpersonal communications did raise concerns about satellite and cellular phone functionality during emergencies, as usage by other organizations would undoubtedly increase, limiting available bandwidth and exacerbating voice delays.

Most participants stressed the importance of owning and maintaining their own backup wireless systems for emergency field communication — a practice followed by all the participants.

June 19, 2017

WECC Generation, Transmission Loss Events Spike

By Jason Fordney

Electric system disturbances resulting from the loss of generation or transmission in the U.S portion of the Western Interconnection increased by 50% between 2015 and 2016, according to a new report from the Western Electricity Coordinating Council.

There were 24 “loss of generation or transmission” events in 2016 compared with 16 in 2015, WECC said in its State of the Interconnection report. The category refers to the loss of three or more Bulk Electric System facilities from a common cause, or the loss of 2,000 MW or more of generation.

WECC did not provide detail on the reason for the increase and did not immediately respond to a request for more information.

Loss-of-load events in the interconnection also increased between 2015 and 2016, from one event to five. These events are defined as loss of firm load for 15 minutes or more exceeding 300 MW for entities with demand of 3,000 MW or greater in the previous year, or exceeding 200 MW for all other entities. There were three loss-of-load events in 2014.

The largest loss of load occurred Aug. 7, with the loss of 665 MW, about 0.5% of the day’s peak system demand of about 127,000 MW.

Not all bulk power system disturbances qualify as loss-of-load events, and “relatively few meet the criteria,” WECC said.

Noting the increase, WECC said that “more years of data will be necessary to determine whether this signifies an increasing trend and potential concern, a statistical anomaly or normal variation between years.”

“Loss of monitoring or control” events — those lasting 30 minutes or more that affect an entity’s ability to make operational decisions — also increased in the Western Interconnection last year. There were 20 such events in 2015 and 22 in 2016.

Islanding events — unintentional system separation resulting in an electrical island of 100 MW or more — dropped from eight in 2015 to just one in 2016.

Incidents in which a remedial action scheme failed or was enacted unnecessarily dropped from four in 2014 to three in 2015 and 2016.

The Western Interconnection housed a combined nameplate generation capacity of 267,000 MW in 2016, up 1% from the previous year. Natural gas-fired generation represented the largest share (40%), followed by hydroelectric (27%), coal (14%) and wind (8%), with the balance coming from solar, geothermal, nuclear and “other” utility-scale generation.

In 2016, “retirement of coal and steam turbine gas units led to slight decreases in capacity from these fuel types, while the installed capacity of utility-scale solar increased by over 6,000 MW,” WECC said. There is about 14,350 MW of solar in the interconnection, or about 5% of capacity.

Hydro dominates in the Northwest, while California and the Southwest are heavy with natural gas. Solar capacity is growing in California, and wind capacity is increasing in the Rocky Mountains and along the Columbia River.

WECC is the regional entity responsible for compliance monitoring and enforcement in the Western Interconnection, which spreads west from the Rocky Mountains to California, north into western Canada and south to Mexico’s Baja California Peninsula. It consists of 37 balancing authorities and is one of four major interconnections across North America. The WECC report covers the bulk power system, which does not include local electric distribution systems.

The WECC Board of Directors is due to receive an update regarding the State of the Interconnection report at its June 21 meeting in Salt Lake City.