Page 1298 – RTO Insider

June 26, 2017

After 10 Years, Time to Prune Reliability Standards, FERC Told

By Michael Brooks

WASHINGTON — A decade of mandatory standards has improved the grid’s reliability, but it’s time for regulators to prune unnecessary rules, speakers told FERC on Thursday.

At its annual technical conference on reliability, the commission delved into the weeds on compliance enforcement, gas-electric coordination and cybersecurity (AD17-8).

ferc reliability — FERC Technical Conference underway | © *RTO Insider*

NERC received accolades from many who spoke at the conference for its continual improvement of the grid’s reliability; its transparency and coordination with other stakeholders; and its Reliability Assurance Initiative, a risk-based approach to compliance enforcement approved in 2015 that allows facilities to self-log minor violations — and NERC to focus on the most serious issues. The initiative also included the creation of Inherent Risk Assessment (IRA) profiles for facilities, which help NERC decide what standards to focus on.

FERC’s conference came days after the 10th anniversary of the first mandatory reliability standards under FERC Order 693 and a week after NERC released its State of Reliability report, from which CEO Gerry Cauley recounted some key statistics in his opening remarks. (See NERC: Despite Solid 2016, Grid Threats Remain.)

“Bulk Power System reliability remains very high and continues to show year-over-year improvement,” Cauley said. “Industry has been very responsive to our risk-based approach and has been shifting resources to fix the most critical challenges to reliability. … These standards have had a major impact on reducing risk. Over time, we’ve seen a dramatic decline in the number and severity of compliance violations.”

But Cauley and many other panelists said it was time for another “Paragraph 81” process, referring to a provision in the commission’s March 2012 approval of NERC’s Find, Fix, Track and Report process that directed the organization to identify requirements that do little to protect reliability and could be removed. FERC ended up approving the retirement of 34 such requirements (RC11-6, et al.).

“It may be time to focus again on streamlining the requirements to ensure the investment in compliance is commensurate with the reliability gains,” Cauley said.

Risk-Based Approach

Speaking on behalf of the Large Public Power Council, Steven Wright, general manager of the Chelan Public Utility District in Washington state, wanted to go a step further. The risk-based approach hasn’t reduced Chelan’s documentation requirements: Of the 1,236 requirements and sub-requirements applicable to the utility, only four qualify for self-logging, Wright said.

He suggested that entities be granted waivers from certain standards if the IRA indicates their implementation of them doesn’t affect the grid.

Cauley disagreed with that idea, calling it an “optional menu.” NERC’s Regional Entities “legally have the discretion today to monitor and enforce whichever standards we feel suit an individual entity. And that’s really the purpose of the Inherent Risk Assessment. … I think the regions could do a better job of explaining that and explaining what could be looked at.

“But I don’t think it makes sense to take a North American set of standards and create sort of a little checklist matrix for each entity. The standards are the standards.”

Wright also suggested that there be more incentives for entities’ standard compliance, which Commissioner Colette Honorable pushed back on.

“I have a 16-year-old daughter, and she gets good grades. But I think she could get better grades,” she said. “So do I reward her for … getting the grades she should be getting anyway?”

Wright did not directly respond to the question of carrot vs. stick, but he made clear he felt LPPC’s members haven’t gotten enough “bang for our buck.”

“We are spending a lot of money” on IRAs and Internal Controls Evaluation, another RAI component, he said. “And I think it’s a good thing because we’re improving reliability, but if we can find efficiencies we should get them.”

‘Special Assessment’ on Gas Dependence

Acting FERC Chair Cheryl LaFleur asked what the commission or NERC should be doing to account for the increasing reliance on natural gas pipelines for baseload power. She pointed out that FERC has no jurisdiction over the reliability of natural gas pipelines (which belongs to the Transportation Department’s Pipeline and Hazardous Materials Safety Administration), but it does have jurisdiction over those who burn the gas.

“Should we be changing our planning standards in some way to take that potential loss of the pipeline into account or the gas storage” site? she asked. “Aliso Canyon brings that into the front of the discussion.”

Cauley responded that NERC is working on a special assessment report on the issue. The organization has been analyzing key pipelines and storage facilities and the potential impact of losing them on the grid.

“It will be clear from this report, I believe, that you should be planning for the loss of a most critical, most impactful facility, including if it’s on a gas system,” he said. “I am concerned that you have certain reliability standards and expectations on an electric system and what I consider a foundational piece — the fuel deliverability piece — doesn’t have an equivalent.”

Patricia Hoffman, acting assistant secretary of the Energy Department’s Office of Electric Delivery and Energy Reliability, suggested that grid operators do assessments to determine how dependent regions are on one fuel source.

Cybersecurity

The threat of cyberattacks took up a sizeable portion of the daylong conference.

NERC Chief Security Officer Marcus Sachs revealed that the organization had only learned about the most serious threat to date — malware known as CrashOverride — days before it was made public by two cybersecurity firms earlier this month. The program, which can control circuit breakers via supervisory control and data acquisition (SCADA) systems, was used last December to briefly cut power to about one-fifth of Kiev, Ukraine. (See Experts ID New Cyber Threat to SCADA Systems.)

Sachs recounted that NERC learned of CrashOverride on the afternoon of Friday, June 9. ESET, a Slovakian antivirus software provider, had contacted Maryland-based Dragos, asking it to review its findings before it publicized them on Monday. Dragos then contacted NERC, which worked over the weekend reviewing ESET’s work and producing a report. Dragos also produced its own report over the weekend.

“If we didn’t have those public-private partnerships already existing, we would have failed that weekend, and you would have had a huge media splash on Monday morning that none of us would have been ready for,” Sachs said.

Many experts believe hackers based in Russia are behind the attacks on Ukraine, which Sachs said has been under “relentless assault” for the past couple years: Banking, railroads and Internet service providers have all experienced disruptions.

But while everything points to Russia, it is also possible individuals posing as Russians are behind the attacks, Sachs said.

Speaking to RTO Insider, Sachs pointed to the Solar Sunrise incident in 1998, in which two teenagers from California attacked Defense Department systems and led the military to believe they were from Iraq. “Just because it looks like a duck, smells like a duck, quacks like a duck — it may be a moose,” he said.

There was considerable discussion about understaffing at the entities responsible for protecting against cyber threats. Many agreed that the supply of qualified cybersecurity workers is too small to meet the very high demand.

“At the state level, we’re generally not staffed for this type of thing,” New Hampshire Public Utilities Commissioner Robert Scott said. “We don’t have the expertise.”

“The electric utility, 30 years ago, was the place to go to out of college,” said Greg Ford, CEO of Georgia System Operations, a cooperative that provides power to half the households in the state. “Today it’s harder and harder to lure those college students.”

“It’s easier to find individuals who are familiar with cybersecurity when it comes to traditional [information technology] and Windows-based infrastructure,” said David Ball, director of AEP Transmission Dispatching. “The more difficult skill set to find today is … a power-based background” and familiarity with SCADA.

“People with these type of skills are very marketable and they’re very mobile,” Scott agreed. “At the state level, we can’t hope to attract those type of people.”

Sachs pointed out, however, that middle and high schools are increasingly sponsoring competitive cybersecurity exercises and students are competing in “hack-a-thons.”

“This is good news,” he said. “And it’s something we need to leverage. … Getting into cybersecurity is absolutely what we want these young kids to do.”

“All I can say to that is ‘Amen,’” Honorable replied.

June 26, 2017

MISO BoD Briefs: June 22, 2017

BRANSON, Mo. — The MISO Nominating Committee has waived Board of Directors term limits and unanimously voted to allow current Director Baljit Dail to stand for an additional term, board Chairman Michael Curran said last week.

miso board of directors — Curran (L) and Dail | © *RTO Insider*

Dail, who this year reached the board’s limit of three three-year terms, will be included on a slate of qualified candidates being prepared by consulting firm Russell Reynolds.

With five first-time directors added since 2015, the veteran agreed to seek re-election for an additional three-year term, but that required the waiver. (See “Committee Could Lengthen Board Member’s Tenure,” MISO Board of Directors Briefs.)

Curran said the committee approved the waiver with an understanding that it should be used sparingly.

“Only in very unique situations should we hand out a waiver. It’s not something that we should use all the time,” Curran said at a June 22 board meeting. The committee cited Dail’s much-needed information technology experience as the reason for the waiver.

The board is unlikely to confront another waiver situation within the next six years based on the terms of current directors, Curran said.

The terms of Thomas Rainwater and Paul Bonavia also expire at the end of this year, but neither have reached the term limit and both will seek re-election.

At the June 21 Advisory Committee meeting, Wisconsin Public Service’s Chris Plante said retaining Dail for an additional term can help educate MISO’s newer board members and keep valuable institutional knowledge in the board.

“This should not be seen as a routine thing,” cautioned Arkansas Public Service Commissioner Ted Thomas.

MISO Reports Likely Year-End Overage; Board Urges Staff Stick to Budget

MISO expects to finish the year 1.2% over budget, Chief Financial Officer Melissa Brown said during a quarterly finance report to the board.

Year-to-date, MISO is $1.5 million under budget, mostly because of late start times on projects and delayed employee travel, according to Brown. The RTO will also save about $1.1 million during the year, in part because of the cancellation of a forward capacity market in retail-choice areas. Still, that savings will be erased by a lower-than-expected employee vacancy rate, resulting in an unexpected $1.5 million spend.

Brown expects the unusually low vacancy rate will persist for the remainder of the year. That, coupled with unforeseen expenses related to upgrading IT systems and miscellaneous overages, could push spending to $241.4 million, against the 2017 budget of $239.1 million. However, expenses could range anywhere from $238.8 million to $241.9 million.

Curran said the RTO should be able cover the forecasted overages with reductions in other spending. “We’re hopeful that we can dial that in with six more months to go,” Curran said, adding that savings shouldn’t come at the expense of project progress.

With labor costs comprising about 60% of MISO’s annual budget, it will be difficult to find cuts that don’t impact labor, Brown said.

Director Todd Raba also requested that the RTO make up the overage with other cutbacks.

Additionally, MISO has so far spent about $15.1 million of its $29.9 million capital budget, which should leave spending on target by year-end, according to Brown.

— Amanda Durish Cook

June 26, 2017

NY Bill Sets Stage for Storage Targets

By Michael Kuser

ALBANY, N.Y. — New York lawmakers last week unanimously passed a measure requiring the state’s Public Service Commission to set targets to increase the adoption of energy storage in the state through 2030.

The new law requires the commission to work with the New York State Energy and Research Development Agency (NYSERDA) and the Long Island Power Authority to set targets and develop a storage deployment program.

“This newly passed bill gives New York’s PSC clear direction: set a storage target and design a deployment program by the end of 2017,” said Anne Reynolds, director of the Alliance for Clean Energy New York. “This is a great signal to the storage industry that New York will be a promising place to invest. But first we need Gov. [Andrew] Cuomo to sign it into law.”

The Energy Storage Deployment Program bill combined Assembly and Senate measures sponsored by Assemblywoman Amy Paulin and Sen. Joseph Griffo.

Both sponsors of the legislation pointed to enhanced reliability of the electric grid as a top benefit of increased use of energy storage, as well as the jobs expected to be created.

A NYSERDA study earlier this year found that about 4,000 workers were employed in the state’s energy storage industry by the end of 2015, up 30% since 2012. The study projected the state’s industry could grow from about $1 billion in revenue to up to $8.7 billion in 2030, with the number of jobs possibly exceeding 25,000.

new york legislation energy storage — EOS Energy Storage Project | *EOS Energy Storage*

“Storage also increases the resiliency of the electric grid by supplying power in the event of an electrical outage. The creation of an energy storage deployment program will increase the installation of energy storage systems throughout the state and accelerate these benefits,” Paulin said in a statement after the bill’s passage.

Setting Targets

Because energy storage is applicable to so many electricity grid functions, a narrow focus on one area fails to capture the complete value of the technology, according to Dr. William Acker, director of the New York Battery and Energy Storage Technology Consortium.

“By analyzing the system as a whole and setting targets, you’re able to create a situation where the energy storage can be adapted into a variety of different applications,” Acker said. “That will open up the markets and lead to penetrations that are far greater than the targets that will have been set. The energy storage industry has made rapid technological advancement over the past few year, but equally important, the costs have dropped dramatically in terms of both the technology and the scale of production.” (See Storage Technology Still Outracing RTO Metrics, Rules.)

Reynolds said her group looks forward to working with the PSC to create a workable program and targets.

“Since it is up to the PSC to determine the specific target by the end of December, industry members do not yet know what impact this could have,” Reynolds said. “New York’s ambitious renewable energy mandate is 50% by 2030. Technically speaking, we do not absolutely need storage to get there, but it can be an excellent complement to increasing renewables deployment and boosting overall system efficiency.”

The state’s Clean Energy Standard, part of Cuomo’s Reforming the Energy Vision initiative, mandates that 50% of electricity generation come from renewable resources by 2030.

New Commissioners on PSC

The Senate on June 21 approved NYSERDA CEO John Rhodes to serve on the PSC, along with former state Sen. James Alesi and Philip Wilcox, an official with the International Brotherhood of Electrical Workers, a union that represents power plant workers. Cuomo has named Rhodes as chair of the commission.

The Senate also reconfirmed Diane Burman for a second six-year term as commissioner after her current term ends next February. The term of Gregg Sayre, who has been serving as interim chair of the commission, also ends next year.

June 23, 2017

MISO Steering Committee Elections Decision Delayed

By Amanda Durish Cook

BRANSON, Mo. — A proposal to detach the appointment of MISO’s Steering Committee leaders from the election of the RTO’s Advisory Committee has been put on hold until late July.

The RTO’s Stakeholder Governance Guide currently calls for the vice chair of the Advisory Committee to serve as chair of the Steering Committee and vice versa. (See “MISO May End Automatic Steering Committee Leadership Posts,” Organization of MISO States Board of Directors Briefs.)

“Today, the Advisory Committee elects the Advisory Committee chair and vice chair, and then by way of peculiarity, they do a flip-flop” to lead the Steering Committee, Entergy’s Matt Brown said during a June 21 Advisory Committee meeting.

Representing MISO’s Transmission Owners sector, Brown proposed a sector email ballot to change the practice. The motion asks that “nominations be solicited annually for the Steering Committee chair and vice chair positions” and that the posts be open to any interested stakeholders. Elections would be decided by the Advisory Committee via sector vote.

Still, a majority of stakeholders in attendance voted to table the motion until the committee’s next conference call on July 26.

MISO Steering Committee Manitoba Hydro Advisory Committee — Elliott (left) and Penner | © *RTO Insider*

Brown said the current Advisory Committee chair and vice chair ― Manitoba Hydro’s Audrey Penner and NRG Energy’s Tia Elliott ― should be able to fulfill their current Steering Committee terms until the end of the year to avoid a leadership shake-up. The motion asks for elections to begin in 2018.

“It’s not the most important issue facing MISO now,” Brown admitted. “However, it’s important to the MISO Transmission Owners.”

Brown said sectors should vote to end the “unusual” practice of automatic leadership and move to “a more conscious choice.”

“This has absolutely nothing to do with the people that currently hold these roles,” Brown said. He recommended the vote to help the Steering Committee attain a level of independence from the Advisory Committee that is “impossible to achieve today.”

Elliott asked if the proposal was aimed at “fixing” something specific that the Steering Committee failed to address.

“This is not anything specific,” Brown replied. “This is not about any actions or decisions of the Steering Committee or any actions or decisions of its current leadership.”

Northern Indiana Public Service Co.’s Paul Kelley said the move was simply a response to a request by MISO Director Thomas Rainwater at the last Advisory Committee meeting to identify attainable stakeholder process improvements.

MISO Stakeholder Relations staffer Alison Lane said the Steering Committee’s dependent leadership posts were created about eight years ago with the Steering Committee itself. At the time, it was viewed as a “cohesive way” to coordinate with the Advisory Committee.

“That’s based on an eight-year-old memory,” Lane said after a beat.

June 23, 2017

NG Lobby Goes on Offensive vs Coal, Nukes

By Rich Heidorn Jr.

WASHINGTON — A key natural gas trade group released a study Thursday that contends it is not fuel diversity but the presence of “reliability attributes” that policymakers should seek for the good of the grid.

And how does natural gas-fired generation fare on that report card? Very well, thank you.

The study, done by The Brattle Group for the American Petroleum Institute, concludes that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes it identified, which included the ability to provide ancillary services, fuel security and proximity to load. Gas excelled on every measure except for storage capability.

american petroleum institute natural gas — | *API/Brattle Group study*

The next best alternative source was pumped hydro with 10. Nuclear and coal, the potential beneficiaries of policies favoring traditional “baseload” generation, fared far worse at five and four respectively, as did wind (one) and solar (two).

Ancillary Services’ Growing Importance

The report calls for RTOs and ISOs to further develop markets for ancillary services, which it said are becoming increasingly important because of the rising share of intermittent renewable generation.

“Policy and market design had not focused on ancillary services until relatively recently. After the provision of energy, generation resources historically had the capability to provide more ancillary services than systems required,” the report says. “Renewables increase the uncertainty and variability in net load and make ramps larger, thereby increasing the ancillary service requirements. In addition, higher renewable penetration depresses energy market prices. This reduces margins earned by resources in the energy market and increases the need to compensate resources for the ancillary services they provide.”

In a press briefing, API Chief Economist Erica Bowman said her organization wants “to push back against” state policies that seek to maintain coal and nuclear plants “at any cost.” API absorbed the smaller America’s Natural Gas Alliance (ANGA) in 2015.

API and its affiliates have been “100% against” policies providing state-backed funding streams for nuclear plants, spokesman Mike Tadeo said.

API said the report was not ordered to counter Energy Secretary Rick Perry’s grid reliability study, which critics have said is designed to benefit coal and nuclear generation. Bowman added, however, that she hoped the Energy Department researchers “use [the findings] as a resource.”

Perry told a House Appropriations subcommittee Tuesday that the report would be released by the end of June, but a department spokesperson said later it would not be ready until July.

Beyond the Reserve Margin

Bowman said grid operators’ traditional reliance on reserve margins — the difference between installed capacity and peak load projections — is no longer sufficient.

“In reality — and NERC has also talked about this — that needs to transition to looking at these other attributes as well,” she said.

Most of the grading on the 12 attributes is likely to be uncontroversial. Also included in the list were generation capability; dispatchability; start times; ramp rates; inertia; frequency response; reactive power; minimum load level; black-start capability; and proximity to load.

But Brattle’s description of gas as “relatively advantaged” regarding the security of its fuel supply supply — along with coal, nuclear and pondage hydro — may come as a surprise to officials in PJM and ISO-NE, which have been encouraging gas generators to add dual-fuel capability. Gas generators can lose their access to fuel during winter peaks, when heating load with firm contracts takes precedence.

The study concedes that — unlike coal and nuclear fuel — “natural gas is rarely stored in large quantities on site,” adding “some natural gas-fired plants have the capacity to burn distillate oil stored in tanks on-site in the event of a natural gas supply interruption.”

It also acknowledges that gas supplies “can be interrupted due to a lack of capacity when demand is very high” — singling out New England’s pipeline capacity constraints — but says “firm supplies have very low probability of interruption.”

Unmentioned in the study is that many gas-fired plants have interruptible contracts because operators say firm pipeline contracts are too expensive.

In its 10-K report for 2016, Calpine — North America’s largest operator of natural gas-fired power plants — warned investors that pipeline constraints “could interrupt the fuel supply” to its plants in PJM, although “some” have dual-fuel capability.

Brattle defended the omission, saying the paper was about compensating units for their reliability attributes, not about the cost of interruptible contracts. “The authors note that cost and environmental attributes may also affect market design. This paper focuses solely on reliability attributes and on the appropriate principles for compensating resources that provide those reliability attributes.”

‘A Lot of Affordable Gas’

Bowman rejected the idea of maintaining coal and nuclear plants as a price hedge in case gas prices rise from their current lows, insisting that the addition of natural gas and renewables has resulted in the most diverse generation fuel mix in history.

She cited a 2016 study by IHS that said the U.S. has 1,400 Tcf of natural gas recoverable at $4/MMBtu — a two-thirds increase over 2010 estimates. The U.S. consumed 27.5 Tcf in 2016.

“There is a lot of affordable gas out there,” she said. “So I guess the real question is how much are you willing to pay for that hedge? I would argue that that would be a lot higher than looking at where natural gas resource affordability is today.”

Wind, Nuclear, Coal Groups Respond

Two competing trade groups weighed in with responses to the API/Brattle study.

“Decades of engineering experience demonstrates that a reliable electricity system needs a diverse portfolio of generation technologies, including nuclear and natural gas,” said Maria Korsnick, CEO of the Nuclear Energy Institute, in a statement. “A close reading of the Brattle study reinforces the conclusion that grid reliability would be hopelessly compromised without nuclear energy, and we’re at a loss to explain why API is advocating such a risky scheme.”

Michael Goggin, senior director of research for the American Wind Energy Association, the API-Brattle Group report findings are “largely consistent” with those of the Analysis Group in a report recently commissioned by AWEA. “Both reports conclude that the increasingly diverse grid, with the addition of renewable and natural gas generators and the services they provide, is operating reliably and, importantly, that markets are the preferred way to ensure the grid continues to secure the services it needs to remain reliable at the lowest cost to consumers. Notably, neither report finds that ‘baseload’ itself is a grid service necessary for reliability.”

Goggin disputed Brattle’s designation of wind as “relatively disadvantaged” in frequency response, saying wind turbines “can provide frequency response that is an order of magnitude faster than conventional power plants, and today are meeting a large share of ERCOT’s need for frequency response when system frequency is high.” He also said wind and solar plants “have excellent ability” to regulate reactive power — a characteristic Brattle rated as “neutral” — and said the report failed to grade the ability to ride through voltage and frequency disturbances. “Had API examined this, it would have found that wind plants, … thanks to their power electronics, far exceed the capability of conventional power plants to remain online following a grid disturbance,” he said.

“Though the API-Brattle report’s generation assessment downplays the significant reliability capabilities and contributions of modern wind turbines, we believe the commonalities between the reports are more notable,” Goggin said.

Paul Bailey, CEO of the American Coalition for Clean Coal Electricity said “backing up more renewables with new natural gas-fired generation will not solve” the challenges facing the grid. “First, natural gas would have to be available at all times to back up more renewables. However, a significant fraction of natural gas supplies for electricity generation is based on non-firm contracts, which means there is no guarantee that gas will be available all the time. For example, approximately 40% of the gas is supplied under non-firm contracts in PJM and MISO.”

Bailey said increased natural gas could make the grid less resilient. “On the other hand, coal plants are fuel secure because there is a large supply of coal (an average of 90 days) at each plant,” he said. “This is why FERC should adopt regulatory changes that properly value attributes, such as on-site fuel storage, that enhance grid resilience.”

June 23, 2017

CAISO Proposal Would Permit ‘Economic’ Outages

By Robert Mullin

Power producers could temporarily suspend the operations of unprofitable generators not needed for system reliability under a CAISO plan released this week.

The Temporary Suspension of Resource Operations straw proposal, released Wednesday, would allow a plant owner to temporarily take a money-losing generator out of the market short of the “mothball” and retirement procedures already spelled out in the ISO’s Business Practice Manuals. (See CAISO Initiative Could Toss Lifeline to Struggling Generators.)

The proposal stipulates that a resource owner must manage a suspended resource in such a way that it can retain the same megawatt rating and ramping capability as before the shutdown. Any plants denied a request could become eligible for payment under CAISO’s capacity procurement mechanism (CPM), which currently compensates units for specific reliability needs.

While that move would fall far short of establishing a capacity market, it could provide needed financial support to gas-fired generators the ISO identifies as vital for future system needs, particularly in integrating increased amounts of renewable resources. CPM payments would be limited to four-month terms.

The proposal calls for owners to be permitted to shut down a resource for two to four months at a time, with the option to request a subsequent four-month suspension.

A unit approved for shutdown would not be required to respond to “exceptional” — or out-of-market — dispatches issued by the ISO, but it could be recalled for system emergencies, making it eligible for a CPM payment. A suspended unit would be ineligible to be counted in the ISO’s resource adequacy showing during its suspension.

The proposal would allow resources to apply for temporary shutdowns throughout the year, but they must provide notice 60 days in advance of the effective date of the suspension. CAISO, in turn, would be required to notify the resource of an approval or denial of the request eight days before the effective date.

“The ISO will assess requests on the first-come, first-served basis, and there will not be a window that resource owners would need to work around,” CAISO said.

A resource would be required to maintain all environmental operating permits while on shutdown, and it must be fully available for service on its return date, the proposal stipulates. To accommodate “unforeseen circumstances” — such as an expected loss of resources, transmission outages or extreme weather — suspended units must be prepared to return to service within 10 days of being notified by the ISO.

CAISO developed the temporary suspension proposal in response to stakeholder comments filed in a 2016 FERC proceeding over the ISO’s refusal to approve outage requests for three of four units at the 965-MW La Paloma combined cycle plant 140 miles north of Los Angeles (EL16-88).

CAISO economic outages — CAISO’s initiative stems from stakeholder concerns raised during a 2016 FERC proceeding related to the La Paloma generating plant, which filed for bankruptcy late last year after being refused permission to suspend its operations in the ISO market. | *Kern County, California Public Health Services Department*

FERC last October agreed with the ISO’s decision to reject the plant owners’ requests because they were made for economic — and not physical — reasons.

Because the request was economic, it “did not represent an appropriate use of the outage management system as allowed by the CAISO Tariff,” the ISO said.

CAISO also denied an additional request to compensate the units by designating them as reliability-must-run resources, contending that they were not needed for reliability purposes. At the time, 42 MW of La Paloma Unit 2 were under an RMR agreement.

La Paloma filed for bankruptcy late last year, citing $524 million in debt and an “inhospitable regulatory environment.”

Although stakeholders largely agreed with CAISO’s La Paloma response, some asked that FERC direct the grid operator to amend its Tariff to allow for outages based on economic considerations — a request that the commission rejected. The ISO nevertheless committed to establishing a stakeholder process to take up the issue this year.

“Through that process, the CAISO and stakeholders will have sufficient time to consider all pertinent issues, the conditions under which economic outages should be permitted, if at all, and how economic outages would interact with other requirements of the CAISO tariff and with CAISO grid and market operations,” the ISO said.

The ISO has scheduled a June 28 call to discuss the proposal and has asked stakeholders to submit comments by July 13.

June 23, 2017

House Panel OKs Bill Expanding FERC Hydro Authority

By Michael Kuser

A proposed law that would give FERC authority over the licensing of all hydropower projects has advanced to the House Energy and Commerce Committee along with four related bills — but only after a hearing that revealed a partisan divide on much of the legislation.

FERC hydropower — House Energy Subcommittee Meeting

The Energy Subcommittee on Thursday sent the Hydropower Policy Modernization Act of 2017 — and four other energy infrastructure-related bills dealing with natural gas pipelines, electric transmission and grid security — to the full committee despite complaints from Democrats about the Republican-controlled process for drafting the bills and on the substance of some clauses.

The hydropower legislation modifies the definition of renewable energy under the Energy Policy Act of 2005 to include hydropower and designates FERC as the lead agency for federal authorizations, granting the commission discretion to extend preliminary permits and the time limits for construction.

“As we always strive to do, these bills have been drafted with bipartisan input, and in large part we’re picking up where we left off with on last year’s energy bill conference,” subcommittee Chair Fred Upton (R-Mich.) said in his opening remarks.

Not a ‘Murmur’

Ranking member Bobby Rush (D-Ill.) disagreed with Upton’s take on the proceeding.

Rush said that despite coming to negotiate in good faith, two of the bills presented for the markup — the hydropower policy and the Promoting Interagency Coordination for Review of Natural Gas Pipelines Act (H.R. 2910) — “are vastly different from the discussion drafts that had been part of the staff negotiations.”

The two bills did not reflect any of the changes sought by Democrats, such as not allowing aerial surveillance to supplant on-the-ground inspection of proposed project sites. They “instead moved in the opposite direction and are even more problematic for our side to accept,” Rush said. He added that Upton had not responded to the Democrats’ request for a hearing on the hydropower policy legislation with officials from the departments of Interior, Commerce and Agriculture.

“This is yet another instance where once again, Mr. Chairman, our side is left to wonder whether we will ever hear directly from the administration on any bill or topic in our jurisdiction,” Rush said. “Where is the administrator of the EPA, and where is the Secretary of Energy? Six months into the Trump administration and we haven’t heard a murmur from the administrator or the secretary, and it’s high time that we hear from those in the administration who have responsibilities to this subcommittee and to the Congress.”

Minor Amendment

The subcommittee also discussed drafts of the Enhancing State Energy Security Planning and Emergency Preparedness Act of 2017; an amendment to the Federal Power Act related to qualifying a conduit hydropower facility (H.R. 2786); and the Promoting Cross-Border Energy Infrastructure Act (H.R. 2883).

The subcommittee agreed to an amendment to H.R. 2786 — offered by the ranking member of the full committee, Rep. Frank Pallone (D-N.J.) — to reduce the public comment period on facilities from 45 days to 30, rather than the 15 days set out in the draft legislation, which Pallone thought insufficient. The proposed law also would lift the 5-MW cap on what constitutes a conduit hydro plant.

Other Democratic-sponsored amendments did not win acceptance, with the subcommittee dividing on party lines. Democrats voted to forward all the bills except for H.R. 2910.

Rep. Greg Walden (R-Ore.), chair of the full committee, said “We’ve learned that oftentimes dozens of agencies are involved in the permitting process, so it’s time that we address these issues head-on and improve the federal licensing procedures and processes to ensure that we get these projects to market sooner for consumers.”

The bill to streamline gas pipeline permitting substitutes “safety for expediency,” Rush said. Republican members voted down his proposal to cut a section of the bill, “so that states, tribes and local community stakeholders can continue to play an important role in the pipeline permitting process.”

Rep. Kathy Castor (D-Fla.) proposed another failed amendment that would have the Office of Management and Budget determine if the legislation would duplicate other federal efforts or result in wasteful government spending.

More Dissent

Pallone said he was “deeply concerned” over the process the subcommittee had used for the markup.

“The draft released on Tuesday night [June 20] not only failed to address any of the concerns we raised, but actually went so far as to add new sections taken directly from provisions of last year’s Senate energy bill that we had explicitly rejected,” Pallone said. “And this does not bode well for making this a bipartisan process.”

Pallone added that Upton had marked up changes on legislation on state energy security plans that Democratic members first saw Tuesday night and that was never the subject of a legislative hearing or member-level discussion. And the gas pipeline bill was a “completely new and different bill” from the one discussed in May, he said.

“I hope today’s issues represent an aberration and not a new and unfortunate way of doing business,” Pallone said.

Subcommittee Vice Chairman Pete Olson (R-Texas) mentioned that Tropical Storm Cindy the previous day had hit the nation’s first LNG export terminal, Sabine Pass on the Texas-Louisiana border, and led to the evacuation of several offshore rigs in the Gulf of Mexico.

“These threats are real, and as cyber threats evolve, let’s get this right,” Olson said. While Texas isn’t famous for hydropower, it is an important baseload power and should be developed without hindrance, he said. “Lastly, on pipelines, we need these reforms. We’ve seen time and time and time again that the process takes too long and is way too messy. The better we are at getting infrastructure built, the better our economy is.”

Cross-border or Borderline?

Also drawing opposition from Democrats was H.R. 2883, the draft bill authored by Markwayne Mullin (R-Okla.) to “establish a predictable and transparent process to permit the construction of cross-border pipelines and electric transmission facilities.”

Pallone offered an amendment that would not restrict the purview of National Environmental Policy Act reviews to the border area, but have EPA look at environmental impacts across the whole length of such projects. The subcommittee divided 18-12 in rejecting the revision.

Mullin and Rep. Gene Green (D-Texas) said the bill does not impinge on federal environmental reviews necessary under existing law, but heightens the focus on the border-crossing itself.

Rush also opposed H.R. 2883, saying the bill would shift the burden of proof to pipeline opponents to prove that a given project was not in the public interest.

The bill would “allow parties to push projects that are not necessarily in the public interest to move forward in the permitting process,” Rush said. “The new bill would make the process worse, less transparent, less inclusive and ultimately less effective … and lead to greater controversy, increased litigation and longer delays.”

June 23, 2017

Western Utilities Bought 3X Planned Wind, Study Says

By Jason Fordney

Western U.S. utilities procured three times more wind capacity in 2003-2014 than planned, showing there is a limited relationship between electricity resource planning and procurement, according to a new Department of Energy study.

department of energy wind capacity — Actual and planned nameplate capacity additions by resource and contract type for 12 load-serving entities in the West. | *Lawrence Berkeley National Laboratory*

Expansion of nameplate wind capacity by 2015 was expected to be about 15% but was actually about 50%, likely coming from power purchase agreements, the analysis of 12 Western load-serving entities showed. Changes in load growth, regulation and contracting led to adjustments in resource planning, and differences in resource mix came largely from renewable portfolio standards and demand-side management, as well as fuel price changes.

The study considered what types of economic and regulatory information is used in planning and procurement, and examined the value of the planning process in light of its relationship to actual practice. The analysis compared integrated resource plans filed in the early and mid-2000s to the actual procurement that followed.

Although IRPs are designed to ensure that utility investment decisions are as cost-effective as possible, there had been no previous “empirical assessment on the effectiveness of IRP implementation,” said the study, conducted by the Lawrence Berkeley National Laboratory.

“We find that most information produced in the planning phase is generally disconnected from the procurement phase,” the researchers said.

After 2008, adoption of less efficient simple cycle combustion turbines correlated with dropping natural gas prices, which might also have been needed to provide balancing power because of higher usage of intermittent renewables. There was also less usage of coal-fired generation than planned, as difficulties in getting coal plants permitted were mentioned by several LSEs in their resource plans; natural gas was likely used as a baseload power substitute.

The researchers said only some of the forecasts, least-cost/risk portfolios and other information produced during the long-term planning processes were used during the procurement processes, and that procurement decisions relied “extensively on the most recent information available for decision making.”

“These findings suggest that states’ IRP rules and regulations mandating long-term planning horizons with the same analytical complexity throughout the planning period may not create useful information for the procurement process,” the study says.

The study found “in aggregate … a general alignment between planned and procured supply-side capacity. However, there are significant differences in the choice of supply-side resources and type of ownership for individual LSEs.”

Avista, Puget Sound Energy, Seattle City Light and Public Service Company of New Mexico procured less capacity than planned, possibly because of lower load growth, while Idaho Power, PacifiCorp and Portland General Electric procured more capacity than was planned. Idaho Power procured two to three times more wind capacity than planned. Although PacifiCorp had not planned for any wind in 2004, more than half of its procured nameplate capacity was wind.

For the Los Angeles Department of Water and Power, Sierra Pacific, Nevada Power and Public Service Company of Colorado, the largest difference between planning and procurement was substituting natural gas units for coal.

There is no formalization of how utilities should use inputs from their IRPs in their procurement, and there is little evidence regarding how sensitivity and risk analyses used in the IRPs are actually applied in procurement decisions, the study says.

It called for a “more careful” definition of the links between IRPs and procurement, calling it “an important problem as energy technologies, markets, and policy and regulatory goals evolve and become more complex.”

June 22, 2017

Consolidated EIM Proposal Effort Gets Underway

By Jason Fordney

CAISO is seeking comment from market participants on three proposed modifications to the Western Energy Imbalance Market (EIM).

The grid operator on Tuesday kicked off the stakeholder process for the proposals, which include allowing third-party transmission providers to receive congestion revenue when they make unused capacity available between EIM balancing authority areas (BAAs).

caiso eim congestion revenue — | *CAISO*

In response to questions during a call on the initiative, CAISO said transmission owners will not have to turn over control of their transmission facilities to participate and would receive payment only if there is congestion on the system.

CAISO says the measure would increase transfer capacity among members, which the ISO’s internal Market Monitor has pointed out reduces congestion and limits the ability of any single participant to wield market power within its BAA. (See Increased Transfer Capacity Reducing EIM Congestion.) EIM entities can currently collect congestion revenue through an offset, but that functionality is not extended to third parties.

CAISO has proposed allowing third-party transmission in the EIM | © *RTO Insider*

The ISO plans to use its existing functionality for transmission contributions, known as “energy transfer system resources” that are used to track, tag and settle EIM transfers. It will need to establish a pro forma agreement that enables scheduling coordinators to submit transmission contributions on behalf of a third party, and create a new make-whole mechanism that would guarantee a payment from congestion revenue. The ISO is seeking stakeholder input on what level of interval granularity those payments should be calculated and how their associated costs should be allocated.

CAISO also wants to correct an inequity that occurs when an EIM BAA wheels power between other BAAs. Wheel-through BAAs receive some revenue when congestion occurs but are not compensated if there is no congestion. In that circumstance, only the source and sink BAAs accrue benefits when a wheel-through transfer occurs.

“How should we quantify the benefits of providing EIM transfers through an EIM BAA?” CAISO asked in its meeting materials.

The ISO has also proposed a new policy for situations in which market participants change their bilateral schedules after submitting their hourly base schedules. Under current practice, changes made after submission are exposed to real-time imbalance settlement payments.

Settlement can result in either charges or payments, but there is no way for market participants to know the cost beforehand. Proposed changes would allow them to manage their exposure to imbalance settlement charges, CAISO said.

After the comment period ends June 30, CAISO will post a straw proposal on the initiative by July 27 and hold stakeholder meetings in August and September. The EIM Governing Body is set to review the proposals in October, ahead of a decision by the CAISO Board of Governors in November.

June 22, 2017

MISO: $130M Needed for New Market Platform

By Amanda Durish Cook

BRANSON, Mo. — MISO wants to spend $130 million over the next five years to construct a new market platform before its existing one becomes outdated, but its Board of Directors is insisting on a thorough stakeholder review of the project’s cost.

Jeff Bladen, MISO executive director of market design, said the upgrade would involve a “piece-by-piece replacement of components” resulting in a “far more modular platform” compared with the rigidity of the current system, which hinders market changes.

Swapping out market software incrementally instead of introducing a new platform all at once is the safer option, Bladen said.

“The risk of a misstep is far less using an incremental process,” he said during a rare June 20 joint meeting of the board’s Markets and Technology committees.

MISO’s current platform is “inflexible,” and even simple market changes require testing and retesting because of possible effects on other software, according to MISO Technology Executive Kevin Caringer. He likened the new design to Microsoft PowerPoint, which can recognize and accept fonts and graphics from other sources.

Looming Obsolescence

The RTO evaluated its market system last year and concluded it had five to seven years before evolving cybersecurity standards and increasing market complexity render the system — designed in the late 1990s — obsolete and no longer able to clear the day-ahead market. (See MISO Reaffirms 2023 End Date for Market Platform.)

“The time is now to begin long-term investment,” Bladen said. “Findings and conclusions drawn from the evaluation resulted in a clear call to immediately initiate a system upgrade.”

Caringer said MISO will spend about $3 million on cybersecurity to extend the life of the current platform for the five years needed for the switch to a new platform.

MISO is asking for an additional 25% contingency budget for unforeseen expenses in addition to the expected $130 million plan. Staff said it will present final cost estimates to the board in September. The board’s Audit and Finance Committee will decide whether to approve the spending in October, and a full board decision on the budget is set for December.

MISO staff predicts the project will yield a 4-to-1 return on investment, with $201 million in benefits, $254 million in cost avoidance and $111 million in risk mitigation.

Board Scrutiny

MISO board market platform — Baljit | © *RTO Insider*

Director Baljit Dail asked how MISO will prove the benefits and savings to its stakeholders.

Bladen said the RTO can share a recent benefits report once it removes nonpublic information from the document.

“I don’t want this to be jammed into December. At some point, I’m going to ask, has this report been scrubbed and has it been shared with stakeholders? I don’t want that to happen in December,” Dail warned.

Director Paul Bonavia wondered if MISO will give stakeholder groups a chance to collaborate to develop a process for responding to the benefits report.

Bladen responded that MISO expects to follow its normal annual budget process with stakeholder review occurring in the Finance Subcommittee.

“I appreciate that, but the budget process usually doesn’t have $130 million to $160 million in additional spending. One director’s strong counsel to you all is make sure the usual process can handle [this],” Dail said.

Other directors pointed out that the project’s benefits may play second fiddle to the market failure that looms if MISO does not implement a new market platform.

“I’m not too captivated by the benefits. We need to move,” Director Michael Curran said. “I’d love to see the benefits, but we have to spend the money. … It’s a burning platform; it’s a slow burn, but it’s coming.”

“My comment is, however you want to justify the benefit, it needs to be put before the stakeholders,” Dail replied. He suggested that MISO convene a special stakeholder committee to discuss the investment and consequences of not reconstructing the market platform.

“I’d like to see [the stakeholders’] fingerprints all over this,” Curran agreed.

Bladen said MISO could initiate stakeholder workshops to discuss building the platform.

In response to a question from Curran, Caringer said MISO could reach out to developers of its original market platform to help improve the transition. Some longtime MISO employees also have knowledge of the system, he said.

Curran said he wanted to require any potential project vendors to have contact with developers of the original system. CEO John Bear said the board would address that topic in a closed session that immediately followed the meeting.