Page 1262 – RTO Insider

October 24, 2017

RTOs Reject NOPR; Say Fuel Risks Exaggerated

By Michael Kuser, Tom Kleckner, Rory D. Sweeney, Amanda Durish Cook

RTO officials and their Market Monitors on Monday unilaterally rejected Energy Secretary Rick Perry’s proposal to provide price supports to coal and nuclear plants, calling it expensive, inefficient and counterproductive.

The ISO/RTO Council (IRC) led the opposition, with CAISO, PJM, MISO, ISO-NE and NYISO also filing comments in opposition. Also filing statements opposing the proposal were PJM Market Monitor Joe Bowring; David Patton, Market Monitor for MISO, NYISO and ISO-NE; and Keith Collins, head of SPP’s Market Monitoring Unit.

In a joint filing supporting the rule, the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association criticized the RTOs for failing to address trends threatening coal and nuclear generators. (See related story, FERC Flooded with Comments on DOE NOPR.)

They said NERC’s and RTOs’ “confidence in the current state of electric reliability … are based, in large measure, on existing conditions and short-term forecasts, largely ignoring the trend toward premature retirements of baseload coal-fired generating capacity currently available to address reliability and resiliency needs.”

market monitor coal nuclear NOPR FERC ISO-NE — | © *ISO-NE*

The coal groups acknowledged that some RTOs “have tried to explore measures intended to maintain traditional baseload capacity in the market, and have even taken some halting and less-than-full steps in that direction, a tacit recognition that existing market rules and structures are not properly valuing the reliability, resiliency and long-term price stability benefits that traditional baseload capacity provides.”

But it said “the few revisions to existing RTO/ISO tariffs and related market structures and rules have so far been much too little and far too late. Without action by the commission to remedy these tariffs and market structures, the electric system will devolve to lose the value of fuel diversity and end up overwhelmingly dependent on intermittent renewable and natural gas generation.”

Rebuttal

Patton recommended FERC define the contingencies the Department of Energy seeks to address. “Without first identifying in detail the contingencies and associated reliability risks to the system, there is no way to quantify a resilience requirement,” he said.

He said MISO and ISO-NE have already conducted fuel-security studies.

“MISO’s evaluations of the adequacy of the gas pipeline infrastructure found the MISO North and Central regions to be ‘favorably located at the crossroads of pipeline corridors extending from many supply basins … with more than 20 interstate pipelines and significant gas storage resources.’ Hence, MISO’s potential exposure to natural gas supply contingencies is relatively low, and the need for the payments called for under the [Notice of Proposed Rulemaking] is similarly low.”

Patton acknowledged New York and New England are more vulnerable to natural gas system contingencies than MISO. But, he said, “it is highly unlikely that the proposal in the NOPR is a feasible or reasonable means to address these vulnerabilities,” saying dual-fuel capability “has been the most effective and cost-effective means” to address them.

“This illustrates the problems that arise when one starts with a very specific answer, rather than starting with a clearly defined issue or objective and allowing the markets to provide the most efficient answer,” he said.

ISO-NE

ISO-NE found fault with what it called the NOPR’s “one-size-fits-all” approach to the region’s risks and said its stakeholder processes were preferable to the NOPR to “develop market-based solutions, if any are needed.”

“The NOPR does not address these risks, and ISO-NE proposes to instead use the time the region has in 2018 and beyond to quantify its fuel-security risks,” the RTO said.

The grid operator said the NOPR would “significantly undermine the efficient and effective wholesale electricity markets,” and that moreover, “New England has no urgent need to rush to a solution, given that the three-year Forward Capacity Market has ensured resource adequacy until at least 2021, and the region has already taken steps to improve operating procedures and generator incentives to secure firm fuel supplies.”

Commenting on the proposed rule’s estimated burden of $291,042 per respondent RTO/ISO to develop and implement new market rules as proposed, including potential software upgrades, ISO-NE said such efforts would “be in the millions of dollars for each RTO.”

The NOPR would undermine New England’s wholesale electricity markets in two ways, the RTO said: “First, these resources may have no incentive to bid their appropriate fuel and operating costs in the energy market … [and] could profitably bid zero. While there are admittedly few coal resources remaining in the region, if these costly units bid zero, it will undermine price formation in the day-ahead and real-time energy market and increase emissions.”

Second, the RTO said, its FCM enables resources to offer to retire if the market does not clear at or above a specific price: “Normally, as units age and their costs rise, new resources will be more economic than retaining aging units that require a higher price. With full cost recovery guaranteed, however, these aging resources will remain, deterring the development of newer, more efficient and more cost-effective generating units.”

ISO-NE also said it has developed new operating procedures to improve information on generator availability during cold weather conditions, such as requiring generators to report their anticipated availability to the grid, including details on their ability to procure fuel.

The RTO said it also has increased market-side efficiency and improved gas-electric coordination to mitigate the supply problems arising from natural gas pipeline constraints.

“For example, the ISO has shifted the day-ahead energy market timeline to better align the electricity and natural gas markets to give generators more time to procure the gas they need to run,” it said.

NYISO

NYISO asked FERC not to adopt the proposal but said if it deemed action necessary, it should give the RTOs at least 180 days from the effective date of any final rule to submit compliance filings.

“[The] deadlines are simply not realistic and attempting to impose them would not be reasoned decision-making,” the ISO said. “The NOPR’s approach would distort, if not destroy, wholesale market signals needed to attract and retain resources required for reliability.”

The ISO called the proposed grid resiliency pricing rule “flawed” for being premised on inaccurate assumptions and statements as they relate to New York.

“The NOPR does not establish that its proposal is appropriate or that ‘grid resiliency’ issues should be addressed the same way in different regions,” said the filing, adding that the grid operator “is not aware of any imminent emergency likely to develop on the wholesale electric system that necessitates drastic and immediate action.”

All resource adequacy criteria have been satisfied in New York and are expected to continue to be satisfied for the foreseeable future, said the ISO. For example, on Jan. 7, 2014, New York set a new record winter peak load of 25,738 MW during the polar vortex, and “NYISO met all reliability criteria and reserves requirements without activating emergency procedures at any time during the winter operating period. It did so despite significant generator capacity derates on some of the coldest days, including generation resources that would appear to qualify under the NOPR as ‘eligible grid and reliability resources.’”

The ISO said it has made improvements to its energy and ancillary service markets and incorporated features into its capacity market rules “that reflect the importance of resiliency to withstand severe weather events,” including basing the downstate installed capacity demand curves on peaking plant designs that include dual-fuel capability.

PJM

PJM agrees there is an issue with maintaining reliability, but not the one suggested by the department.

“The DOE didn’t exactly get it right in the way it attempted to articulate the problem,” Stu Bresler, PJM senior vice president of operations and markets, said Thursday.

During a special conference call to preview the RTO’s plan for responding to FERC’s request for comments on the NOPR, Bresler said that the real issue is energy price formation. PJM has been working on that topic for more than a year to respond to concerns over public-policy initiatives impacting market prices.

CEO Andy Ott made similar observations during a media call on Monday, calling it “a tall order” to implement the proposal “and then expect the competitive market to continue to function effectively.”

“The DOE proposal, which essentially is the cost-of-service type of mechanism, we don’t believe is workable. We don’t believe that that is an appropriate response,” Ott said. “We believe [it] is contrary to law and will not really solve any problems. … A better and least-cost solution would be to do proper valuation of resource attributes through a market construct.”

Ott said the proposal is discriminatory because it is exclusive to certain technologies, rather than the service provided to the grid, and only in RTOs with capacity markets — such as PJM.

“PJM does have an abundance of coal and nuclear plants that are in the merchant category, so … it does look like this is certainly targeted at the PJM region,” he said. “We do say that in our comments that this proposal does seem to be focused on this region.”

Bresler said that the NOPR — which cited natural disasters and the 2014 polar vortex to argue that units with large on-site fuel stockpiles should be subsidized to save them from retirement — misses the mark. (See FERC’s Independence to be Tested by DOE NOPR.)

“The point is that just maintaining a whole lot of resources with a 90-day fuel supply on site would not have relieved the problems with a majority of the outages during the polar vortex,” Bresler said. “While the polar vortex did highlight the need for the markets to ensure that we are signaling the need for resources to be able to operate on peak days, just resources with long-term fuel supplies on site was not the majority of the issue.”

During natural disasters, Bresler said, the main challenge is downed power lines, not generating plants being unable to run.

“Events like that … primarily affect the delivery system from supply to demand, not the supply resources themselves,” he said, noting that some coal plants impacted by Hurricane Harvey this summer weren’t able to run at full capacity because their coal piles were soaked.

“In the interest of framing the right problem, we will point out these things that we feel sort of led DOE down the wrong path as far as what the actual problem is,” he said. “We will say, however, that there is an issue that we do need to address, specifically to the PJM region. And that is the fact that there are some instances in PJM where not all resources are valued appropriately for the fact that they are relied upon to reliably meet the demand. … We are concerned that resources right now may not be offering as much flexibility as they could provide because they don’t have incentive to do it.”

Using competitive markets to “transparently” price needs is “superior” to providing cost-of-service payments to certain unit types, he said.

“One concern we have with the DOE approach is it seems to imply that while we may need to keep some of these resources around to ensure reliability and resilience, so therefore let’s keep them all,” Bresler explained. “That again is, from our standpoint, inefficient from the standpoint of the cost to load. Whereas the markets, we believe, have done a very good job to provide the discipline for what really is necessary and what’s not necessary and thereby not just provide efficient signals for entry, but also provide efficient signals for exit.”

PJM’s comments to FERC included a version of a proposal staff presented at its August meeting of the Markets and Reliability Committee. Bresler said the proposal will be revised and presented again at the Dec. 7 MRC meeting.

Ott acknowledged that PJM’s comments don’t reflect the perspectives of all its members.

“There really was no full vetting of these comments with stakeholders,” he said. “One, there isn’t sufficient time, and second is … PJM’s comments are PJM’s and we do not vet those through stakeholders.”

In his comments to FERC, Monitor Bowring said approving the DOE proposal “would replace regulation through competition with an unworkable hybrid of competitive markets and cost of service regulation. The eventual result would be the demise of competitive markets in the PJM region.”

“If the reliability rules need enhancement,” he continued, “the reliability rules should be enhanced. The DOE proposal should be rejected. The PJM region needs more competition, not less.”

MISO

MISO’s comments urged FERC not to adopt the proposal, saying it fails to identify imminent reliability or resilience issues, and said its footprint currently doesn’t have any such issues that would warrant immediate action “beyond the application of ongoing processes and existing tools that address resource availability and retirement in the MISO region.” [Editor’s Note: An earlier version of this article incorrectly reported that MISO did not file its own response.]

“Instead of proceeding in haste with material changes that could have broad-ranging and potentially adverse impacts, MISO urges the commission to move at a deliberate pace, to work through its existing dockets and to leverage its established processes to initiate a full, thorough and public vetting of the issues raised by the proposal,” the RTO wrote.

The RTO told stakeholders earlier this month that they would insist FERC respect the RTO’s existing reliability process, and would study frequency control, ramping, voltage support, inertia and inertial response to identify the features of a “resilient” generator. (See MISO Ready to Define, Study ‘Resiliency’ for DOE.)

SPP

SPP told stakeholders Thursday it would will join the IRC filing, pointing to what staff called “some pretty strong comments.”

“The council does a really good job of laying out why this doesn’t work from an RTO perspective,” SPP General Counsel Paul Suskie told the Strategic Planning Committee.

“If you’re a plant under the rule, your costs are totally covered,” Suskie said. “Why would you do anything but bid zero into the market? It will drive costs down further and distort markets further.”

Some stakeholders expressed discomfort with signing onto the IRC comments without seeing the language.

“The basic issue here is the subsidy,” countered SPP Board Chair Jim Eckelberger, saying renewable energy tax credits had led to oversupply. “We don’t want to screw up the market even more. We should take a strong stand here.”

In its call for comments, FERC said the NOPR’s scope applies to commission-approved ISOs and RTOs with capacity markets and day-ahead and real-time energy markets. Noting SPP’s lack of a capacity market, Suskie said while it “appears this rule is not applicable to SPP,” staff will work under the assumption that a final FERC rule could apply to the RTO.

Suskie said the proposed timeline for action is “impractical.”

“Staff would recommend additional time to implement if the final rule applies to SPP,” Suskie said, noting staff would have to compile a list of eligible facilities. “Staff is very concerned. … If you read what the intent appears to be, basically any coal or nuclear plant not [rate-based] within an RTO would have to be fully compensated.”

Suskie asked who would determine a plant’s rate of return and cost of capital.

“Traditionally, those things are decided at the commissions, not RTOs,” he said. “How do you enforce a 90-day coal supply? How do you enforce whether a plant complies with environmental regulations?

“If this is applicable to SPP, it would be a big sea change,” Suskie said.

Keith Collins, executive director of SPP’s MMU, said his group agrees with much of what Suskie said, saying the NOPR is “proposing a solution to a problem that’s not well defined.”

The NOPR “doesn’t define the problem well in a way that’s actionable and measurable,” Collins said. “When you actually read the [recent DOE grid study], it says more work needs to be done to value and define resiliency before you come up with solutions. What’s included, what’s excluded … it’s hard to say.”

Like Suskie, Collins said the 90-day timeline does not allow sufficient time to properly consider the NOPR.

“If there’s a question to be raised, it can be answered over time, but we don’t support what’s going on,” he said. “Competitive forces have been part of policy in the energy and electricity markets over the last 25 years. It will provide new technologies, batteries and the like, that will improve the resiliency for the grid in ways we’re not aware of today.

“What the Energy Policy Act of 1992 did was promote competitive markets and open access,” Collins said. “If someone can provide power cheaper than someone else, they should be able to do that. If I built a plant a while ago that’s unprofitable, that’s a signal. Resources are indicating they are not being able to recover their costs. We see the consequences of a policy like this with our negative pricing.”

In his filing, Collins said “the SPP markets provide insight into the adverse consequences of policies designed to preserve capacity that would otherwise be uneconomic in typical ISO/RTO markets.

“The SPP market, which is dominated by vertically integrated utilities, provides an example of the potential difficulties that will be faced if the Proposed Rule is implemented,” he wrote. “The SPP market has a considerably high capacity margin, currently trending above 40% compared to the 12% minimum requirement in the SPP Tariff. The excess capacity distorts price formation in the competitive market by encouraging price insensitive offer/bid behavior and mutes price signals for others type of generating technologies.”

CAISO

CAISO said the rule would not apply to it because it does not have a capacity market or coal or nuclear resources that would be eligible for the proposed compensation. But it opposed the rule nonetheless, saying “there is no basis for a universal finding that having a 90-day, on-site fuel supply is essential for ISOs and RTOs to maintain grid reliability or resilience.”

Rich Heidorn Jr. contributed to this article.

October 23, 2017

ERCOT Board of Directors Meeting Briefs: Oct. 17, 2017

ERCOT plans to revise its bylaws after discovering that dozens of members could be construed as affiliates under current rules because of stakes owned by investment funds such as Vanguard Group and Fidelity Management and Research.

The ISO learned of the issue from Vistra Energy, which informed ERCOT in September that Vanguard owns more than 5% of its voting securities — the current threshold for presuming that a shareholder exercises “substantial influence or control.”

ERCOT Board of Directors Vistra Energy — Seely | *ERCOT*

ERCOT General Counsel Chad V. Seely told the board Tuesday that further investigation into Vistra’s letter identified 30 members who could be considered affiliates of each other based on common equity investors and that the number could go as high as one-third of the ISO’s 309 members.

Already, more than a dozen companies, including Calpine, Dynegy, Exelon and NRG Energy, have informed ERCOT they are in a situation like Vistra.

In addition to Vanguard and Fidelity, ERCOT said it has determined that at least five other investment firms may own more than 5% of two or more members: BlackRock, Capital Research Global Investors, Hotchkis & Wiley Capital Management, Oaktree Capital Management and State Street Global Advisors.

“In brief, ERCOT legal believes that this is just the beginning of identifying a longer list of potential members who may be affiliates through common equity ownership by a broader list of institutional investors,” Seely wrote board members in a memo.

Seely said companies deemed to be affiliates could be forced to change their industry segment or lose their voting rights.

His office issued membership applications on Oct. 2 for the year 2018. Corporate members must be registered by Nov. 10 to vote on board members at ERCOT’s Dec. 12 elections.

To address the issue, Seely recommended that the ISO revise the affiliate definition in the bylaws. In the interim, he said ERCOT should issue a “blanket” resolution saying that investment companies that own less than 20% of a member are assumed not to have control of the member.

The higher threshold would apply only to shareholders meeting one of the exclusions from the definition of “affiliate” under Texas’ Public Utility Regulatory Act (PURA) or has been determined to hold ownership interests in the member for investment purposes only. Not eligible for the 20% trigger would be members sharing a common parent or board member or under common influence or control of another entity.

Board Nominees

Corporate members will vote during the annual meeting Dec. 12 on a second term for unaffiliated board member Peter Cramton, a University of Maryland economics professor. They also will consider a newcomer, Terry J. Bulger, a banking executive specializing in risk management.

Unaffiliated directors, who serve staggered three-year terms, are also subject to approval by the Public Utility Commission of Texas. (Tuesday was the first ERCOT board meeting attended by new PUCT Chair DeAnn Walker.)

Consent Items

The board approved three nodal protocol revision requests (NPRRs) and one system change request (SCR) on the Technical Advisory Committee consent list.

NPRR768 — Revises the categories of ERCOT-initiated actions that trigger the real-time online reliability deployment price adder pricing run to ensure prices reflect current system conditions.
NPRR821 — Eliminates the congestion revenue right (CRR) deration process for resource node to hub or load zone CRRs, an effort to improve CRR funding.
NPRR840 — Synchronizes the implementation of NPRR782 (settlement of infeasible ancillary services due to transmission constraints) by removing the two-hour advance notice period inadvertently left in protocol language when NPRR782 was approved.
SCR791 — Populates unused megawatt and price values in security-constrained economic dispatch (SCED) generation resource data (GRD) energy offer curves with null values rather than zeroes, to improve the usability of the 60-day SCED GRD disclosure report.

Consent, Non-Consent Items OK’d

The board also approved three additional NPRRs on individual voice votes:

Director Carolyn Shellman, of the Municipal Market segment, voted against two NPRRs, citing budgetary concerns. NPRR817 created the Panhandle 345-kV trading hub that would be excluded from the ERCOT-wide hub average and bus average calculations at an estimated cost of $150,000 to $200,000. “This would reduce the cost of future hubs,” TAC Vice Chair Bob Helton said.
Shellman also opposed NPRR829, which will allow a qualified scheduling entity to provide data on its net generation to the ERCOT transmission grid from their non-modeled generators so that the output can be considered in the estimate of real-time liability (RTL). The change is expected to cost between $200,000 and $300,000. The members of the Municipal segment opposed the proposal, but ERCOT supported it, saying it will improve the calculation of collateral requirements and transparency into non-modeled generation.
The board unanimously approved NPRR836, which incorporates 11 binding document forms into the protocols as a new Section 23, and allows changes to the forms to be made using the administrative NPRR process. Morgan Stanley, a member of the Independent Power Marketer segment, opposed the proposal at the Protocol Revisions Subcommittee.

Line of Credit

After an executive session, the board briefly reopened the meeting to renew its revolving line of credit with JPMorgan Chase.

— Rich Heidorn Jr.

October 23, 2017

PJM: Energy Price Formation Addresses DOE NOPR

By Rory D. Sweeney

PJM agrees there is an issue with maintaining reliability, but not the one suggested by the Department of Energy’s recent call for price supports for coal and nuclear plants.

“The DOE didn’t exactly get it right in the way it attempted to articulate the problem,” Stu Bresler, PJM senior vice president of operations and markets, said Thursday.

PJM DOE price formation NOPR — Bresler | © *RTO Insider*

During a special conference call to preview the RTO’s plan for responding to FERC’s request for comments on the DOE Notice of Proposed Rulemaking, Bresler said that the real issue is energy price formation. PJM has been working on that topic for more than a year to res pond to concerns over public-policy initiatives impacting market prices.

Bresler said that the NOPR — which cited natural disasters and the 2014 cold snap known as the “polar vortex” to argue that units with large on-site fuel stockpiles should be subsidized to save them from retirement — misses the mark. (See FERC’s Independence to be Tested by DOE NOPR.)

During natural disasters, Bresler said, the main challenge is downed power lines, not generating plants being unable to run.

Using competitive markets to “transparently” price needs is “superior” to providing cost-of-service payments to certain unit types, he said.

The response will include a version of a proposal PJM staff presented at its August meeting of the Markets and Reliability Committee. Bresler said the proposal will be revised and presented again at the Dec. 7 MRC meeting.

October 23, 2017

Good Markets, Bad Markets: CEOs Sound off on State Policies

By Rich Heidorn Jr.

WASHINGTON — Panelists at the Energy Bar Association’s Mid-Year Energy Forum last week heard two very different views of the health of wholesale markets.

wholesale markets eba energy bar association — Flexon | © *RTO Insider*

Pacific Power CEO Stefan Bird was effusive in his praise of the Western Energy Imbalance Market (EIM), which saved parent company PacifiCorp almost $9 million in the second quarter of 2017. But Dynegy CEO Robert Flexon complained that CAISO and NYISO had become increasingly inhospitable to merchant generators because of state policies favoring renewables and nuclear generation, respectively.

“For us, the markets are [in an] incredibly fragile situation. California is a disaster. There isn’t any competitive power company out there who wants to put a nickel into California,” he said.

Flexon also bemoaned MISO Zone 4 in Southern Illinois, where he said competitive units face unfair competition from rate-based generation. The state also has approved zero-emission credits for nuclear plants, leading to fears in PJM — whose footprint includes Northern Illinois — that such subsidies will be contagious.

“PJM is doing everything they can to try to keep their market together. They’re very proactive,” Flexon said. “They’re trying to fix price formation and the like. [Having] half our megawatts in PJM, I feel good about that.” (See related story, PJM: Energy Price Formation Addresses DOE NOPR.)

Bird said his company’s experience with the EIM has been an unquestioned success.

Moderator Christopher R. Jones, a partner with Troutman Sanders, had set off the discussion by asking Bird if the markets are “healthy.”

“Are they enabling what our customers want? Are they enabling [a] low-cost, affordable, reliable future? I think the answer is resoundingly ‘yes,’” said Bird, whose company has 740,000 customers in Oregon, Washington and California.

“We’ve really had unprecedented opportunities to move that dial on a very accelerated pace and lower costs as well as reduce emissions.”

He said the EIM’s economic dispatch and its ability to move renewable power to load centers enabled PacifiCorp to announce in June a $3.5 billion investment in renewables and transmission in Wyoming, Utah and Idaho “at very little to no costs for our customers and savings over the long term.” (See PacifiCorp IRP Sees More Renewables, Less Coal.)

John DiStasio, president of the Large Public Power Council, said his members don’t have a single view of the market. His organization, which represents the 26 largest members of American Public Power Association, has members in NYISO, SPP and ERCOT.

“Those members that view that there’s economic benefits for them are participating in markets, and those who don’t see that don’t [participate],” DiStasio said.

He said RTOs have gone through “identity crises.”

“When we started up with CAISO, it was really a traditional RTO. And at some point, state policy started to drive how they looked at supporting environmental policy as well. There’s been hit and miss on how that’s been priced. There’s been hit and miss on how you get the right incentives for capacity in some of the markets.” DiStasio said California’s dominance of CAISO has been a barrier to greater market expansion in the West.

“Having said that … moving energy over wider regions I think is going to have a certain inevitability to it where we’ll have more and more people operating in markets — even if it’s just at the EIM level.

“From a Western perspective, I was appreciative that FERC didn’t try to push the Energy Imbalance Market. Actually, it would have fallen apart had that happened given the history of the [2000-2001] energy crisis, the [1980 Pacific Northwest Electric Power Planning and Conservation Act], given what happened in the Northwest during the energy crisis. I think FERC trying to assert more control at that time actually would have had a negative effect. Now, the market dynamics seem to have emerged organically enough that you have people that are voluntarily creating critical mass.

“I think this is really going to be a delicate balance going forward with how much does FERC push on state policy, and I think they may have to rethink the whole paradigm at some point. Because it is a clearly a hybrid and we’re kind of stuck … in no man’s land.”

When the discussion turned to Energy Secretary Rick Perry’s call for price supports for coal and nuclear plants, Flexon also called for FERC action.

“FERC has been missing while all the mischief has been happening,” he said, referring to the agency’s six months without a quorum. “They need to get back in the game and protect the markets they created.”

October 23, 2017

FERC Seeks Cyber Controls on Portable Devices; Sets GMD Plans

By Rich Heidorn Jr.

WASHINGTON — FERC on Thursday proposed rules to prevent malware from infecting “low impact” computer systems through transient electronic devices such as laptops and thumb drives.

FERC NOPR GMDs cybersecurity — | © *RTO Insider*

The Notice of Proposed Rulemaking would approve critical infrastructure protection reliability standard CIP-003-7, a response to an order issued by FERC in January 2016 (RM17-11). (See FERC Postpones Action on Supply Chain Protections.)

In addition to setting controls on devices frequently connected and disconnected from low-impact Bulk Electric System (BES) facilities, the NOPR also requires such facilities to have a policy for declaring and responding to “exceptional circumstances.”

High- and medium-impact BES cyber systems already have rules for responding to “exceptional circumstances,” which include situations that impact BES reliability or pose the risk of injury or death and cybersecurity incidents requiring emergency assistance.

The NOPR also directs NERC to revise the standard to provide objective criteria for electronic access controls for low-impact systems and add ways to mitigate the risk of malicious code introduced by third-party transient electronic devices, such as scanning devices prior to use.

GMD Order

In a separate order, FERC approved NERC’s preliminary geomagnetic disturbance (GMD) research work plan and ordered it to file a final plan within six months (RM15-11-002).

NERC’s GMD work plan, which it developed in collaboration with the Electric Power Research Institute and its GMD Task Force, identified nine research areas and sets an estimated time frame for their completion. It was developed in response to the commission’s September 2016 order requiring grid operators to assess and protect against the threat of GMDs. (See FERC Approves GMD Reliability Standard.)

Thursday’s order sets the priority in which NERC should conduct the GMD research, saying it should first seek to improve earth conductivity models for studies of geomagnetically induced currents. The commission cited the models’ importance in completing the GMD vulnerability assessments required by reliability standard TPL-007-1.

It said the second priority should be improving harmonics analysis “because the synergistic effects of harmonics during GMD events are not well understood.”

October 23, 2017

‘Momentum’ Seen for U.S. Offshore Wind

By Rich Heidorn Jr.

WASHINGTON — Even as the Trump administration has rejected the Paris Agreement and works to boost coal-fired generation, optimism has been building on the East Coast for the offshore wind industry.

The U.S. market has gained momentum in the last two years, the head of DONG Energy Wind Power U.S. told the Energy Bar Association’s Mid-Year Energy Forum during a panel discussion last week.

energy bar association eba offshore wind — Brostrøm | © *RTO Insider*

President Thomas Brostrøm credited state renewable portfolio standards and carbon reduction goals for creating demand. And he said the shallow waters off the East Coast provide attractive sites like those in Europe.

DONG, the No. 1 offshore wind generator in the world, clearly sees renewables as the future. On Oct. 30, it will ask shareholders to approve changing its name — originally an abbreviation for Danish Oil and Natural Gas — to reflect its commitment to renewable power. It completed the divestiture of its upstream oil and gas business in September. The new name, Ørsted, honors Danish scientist Hans Christian Ørsted, who is credited with discovering electromagnetism in 1820.

The company, which operates more than 1,000 offshore wind turbines in Europe, acquired the rights to develop more than 1,000 MW off New Jersey and is working on a pilot project with Dominion Energy off Virginia. (See Dominion Plans 12-MW Offshore Wind Project, 2nd in US.) It also has formed a joint venture with Eversource Energy to bid on Massachusetts’ solicitation for 1,600 MW of offshore wind.

energy bar association offshore wind eba — Kalpin | © *RTO Insider*

Brostrøm said the industry has matured over the last two decades as it has moved from “bespoke” projects to more standardization. At the same time, the technology has advanced from 3.6-MW turbines in 2009 to 8-MW turbines today, with next-generation models expected at 12 to 15 MW.

The panel discussion, moderated by Holland & Knight partner Mark C. Kalpin, also included Walter Cruickshank, acting director of the U.S. Bureau of Ocean Energy Management, and Curtis Fisher, executive director of the National Wildlife Federation’s Northeast Region.

Since 2009, BOEM has issued 13 offshore commercial wind energy leases, giving leaseholders the right to seek approval for development plans. The U.S. currently has only one operating offshore wind project, Deepwater Wind’s 30-MW Block Island Wind Farm in state waters off Rhode Island, which went into service last December.

“We have quite a bit to learn, still, about how things will operate — how developers will move forward with their projects,” Cruickshank said.

On Aug. 31, Interior Secretary Ryan Zinke, Cruickshank’s boss, signed an order setting a one-year target for completing environmental reviews under the National Energy Policy Act following the issuance of a Notice of Intent. “We haven’t entirely figured out how we’re going to do that yet, but we are working on trying to improve our processes,” Cruickshank said.

Fisher said his organization supports offshore wind when it is sited “in the right places” and construction minimizes impacts on aquatic life. The group is especially concerned that foundations are not drilled during the migration of endangered North Atlantic right whales because the noise can disturb the marine mammals. Fewer than 500 are believed alive.

“This is our big chance” to address climate change, Fisher said. “I fundamentally believe that this is the challenge of our generation — to actually build [renewable] projects on scale to solve problems that many people think are just too big to solve.”

October 23, 2017

ISO-NE Planning Advisory Commitee Briefs: Oct. 18, 2017

ISO-NE will revise the scope of its 2027 transmission needs assessments for Eastern Connecticut, Southwest Connecticut and New Hampshire after stakeholders raised questions about the study’s dispatch modeling, Director of Transmission Planning Brent Oberlin said Wednesday.

“It seems to be as you dial in more and more on the bus basis, the dispatches seem to be very severe in some of the cases,” Oberlin said.

During the September Planning Advisory Committee meeting, ISO-NE presented the assumptions and study methodology behind the 2027 Needs Assessment Scope of Work, a study produced biannually to provide insights into the system 10 years into the future. (See “2027 Needs Assessment Scope of Work,” ISO-NE Planning Advisory Committee Briefs: Sept. 28, 2017.)

“If you look at the difference between the 90/10 cases and the 50/50 load level cases, you can see things becoming even more severe beyond what was anticipated using this new method, so we are going back and kind of hit the pause button for a second here trying to understand exactly what’s happening, what’s causing it,” Oberlin said. “We plan to come back to the November PAC to go into more detail on the issues that we’re seeing.”

Regional System Plan Tx Projects Update

Cost estimates have changed significantly for two transmission projects since the last Regional System Plan update in June 2017: the Connecticut River Valley project in Vermont (down $9.8 million) and the Maine Power Reliability Program project (up $7 million).

Fabio Dallorto, an ISO-NE transmission planning engineer, spoke about the projects and asset conditions during an update to the PAC.

The Vermont project (No. 1614) entails rebuilding a 115-kV line from Coolidge to Ascutney to resolve thermal overload. The decreased costs reflect competitive bids throughout the project and a reduction in the amount of contingency — from 50% to 10% — included in the estimates now that the projects are better defined, Dallorto said.

The RTO reported no new projects but said 16 upgrades on the project list have been placed in service since June, including four in the greater Boston area.

Western Mass. Structure Replacement

John Case of Eversource Energy reported that 19 of 263 structures on the 1231/1242 lines in western Massachusetts need to be replaced to maintain reliability. Some of the structures are more than 90 years old, and one crossing the Deerfield River lacks shield wire, which was inexplicably not replaced following a helicopter crash that damaged the wire several years ago.

ISO-NE REV William Scherman Interregional Transmission Planning — Western Mass. transmission structure damage | *Eversource Energy*

The majority of structures on the circuits are double-circuit steel lattice towers. Replacing them reduces the potential for structural failures, Case said.

The project’s scope includes installation of 15 115-kV double-circuit and four single-circuit light-duty weathering steel structures to replace lattice towers.

Eversource estimated the project will cost $8.1 million.

Environmental Update Cites Uncertainty at Federal Level

Emphasizing the “uncertainty and the changes that are afoot at the federal policy level,” ISO-NE senior analyst Patricio Silva spent half an hour updating the PAC on all relevant environmental policy and regulatory matters affecting larger generation and linear transmission projects.

“We’re seeing significant changes with the Clean Air Act, Clean Water Act, Resource Conservation Recovery Act and the National Environmental Policy Act, [which] is actually having a dramatic impact in a variety of different regulatory forms,” Silva said during his presentation.

Silva pointed out that the Trump administration has advanced with its proposed withdrawal from EPA’s Clean Power Plan, which would affect carbon dioxide emissions from existing electric generating units. (See EPA to Announce Clean Power Plan Repeal.) The agency’s New Source Performance Standards for carbon emissions are also in limbo pending a review, and related litigation has been stayed. The agency’s pause, now reversed, in implementing new ozone standards also triggered litigation, he said.

“Lastly, more technical, but of particular interest to generators, there are changes afoot in the regulations under the Clean Air Act covering start-up, shutdown and malfunction events at generators,” Silva said. “That is a rule that’s under reconsideration and that’s also subject to litigation.”

Silva noted that his presentation only covered the Clean Air Act. “I hope you’re taking away from this that there’s a lot going on and we do not know what the outcome may be on some of these actions,” he said. “In fact, we do have in the oil and gas sector under the Clean Air Act an example of a misstep, where EPA paused and stopped to reconsider a rule only to have the litigation that was being used by the industry to stop the rule swept away.”

With the Trump administration rejecting EPA’s previous approach and the D.C. Circuit Court of Appeals essentially putting rules into effect mid-step, “there’s a risk of regulatory snap-back, where depending on where the EPA is procedurally with a reconsideration or a policy or implementation change, an affected industry sector may suddenly discover that they’re facing a fully implementable standard with a compliance deadline that has passed,” Silva said.

ISO-NE is closely watching upstream oil and gas policy because it could have a variety of implications under the Clean Air Act, especially for the operations of existing and new generators, he said.

— Michael Kuser

October 23, 2017

PJM MRC/MC Preview: Oct. 26, 2017

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

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

Markets and Reliability Committee

2. PJM Manuals (9:10-10:00)

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

A. Manual 11: Energy & Ancillary Services. Revisions, which also include changes to the Operating Agreement (OA) and Tariff, were developed to address capping of intraday offers. The current rule offer-caps units that fail the three-pivotal-supplier test, but prohibits reapplying the cap during the unit’s day-ahead commitment or minimum run time. The changes would re-evaluate capped units when offers are updated. The changes would also apply to self-scheduled resources. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

B. Manual 11: Energy & Ancillary Services. Revisions developed for the offer-verification process and offer-capping logic as part of implementation of FERC Order 831. The Independent Market Monitor, which disagrees on some parts of PJM’s proposal, will offer comments. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

C. Manual 14B: Regional Transmission Planning Process. Revisions developed to add information related to contingency definitions.

D. Manual 19: Load Forecasting and Analysis. Clarifies when load drop estimates are produced and includes updates from a periodic review of the manual. (See “Cleared PRD Forces Manual Revisions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

3. Balancing Ratio (10:00-10:20)

Members will be asked to endorse Tariff revisions addressing the calculation of the balancing ratio used in determining the market seller offer cap (MSOC) for the 2018 Base Residual Auction, along with an associated problem statement and issue charge. PJM is concerned that there have been no penalty assessment intervals as needed to determine the balancing ratio. The problem statement and issue charge are meant to address the issue permanently. (See “Give me a B…,” PJM MRC/MC Briefs.)

4. Distributed Energy Resources Update (10:20-10:40)

Members will be asked to endorse a proposed Distributed Energy Resources (DER) Subcommittee charter. A proposed revision that was not considered friendly by other stakeholders is being offered as a separate version. (See “Amendment on DER Charter Sparks Debate,” PJM MRC/MC Briefs.)

5. 2017 Installed Reserve Margin Study Results (10:40-10:50)

Members will be asked to endorse the 2017 installed reserve margin (IRM) study results. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

6. Restoration Planning Generator Data (10:50-11:00)

Members will be asked to endorse OA revisions associated with PJM sharing of restoration planning generator data with Transmission Owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)

Members Committee

Consent Agenda (2:20-2:25)

Members will be asked to endorse:

B. Tariff and OA revisions to clarify definitions, as recommended by the Governing Document Enhancement & Clarification Subcommittee.

1. RPM Market Seller Offer Cap (1:25-1:45)

Members will be asked to endorse proposed provisions for calculation of the balancing ratio used in determination of the MSOC for the 2018 BRA. (See MRC agenda item 3 above.)

2. Intraday Offer Capping (1:45-2:00)

Members will be asked to endorse OA and Tariff revisions associated with capping of intraday offers. (See MRC item 2A above.)

3. 2017 Installed Reserve Margin Study Results (2:00-2:15)

Members will be asked to endorse the 2017 IRM study results. (See MRC item 5 above.)

— Rory D. Sweeney

October 23, 2017

New York PSC Adopts DER Rules, Sanctions ESCOs

By Michael Kuser

The New York Public Service Commission on Thursday enacted consumer protection standards for distributed energy resource suppliers.

The PSC’s order also created a manual of uniform business practices, the first rule of which stipulates that “a DER supplier shall obtain a customer’s consent to a sales agreement prior to billing a customer or enrolling a customer” in any program.

NYPSC DER distributed energy resources ESCO ESCOs — Kelly | *NY DPS*

At the commission’s monthly meeting in Albany on Thursday, Ted Kelly, assistant counsel for the state’s Department of Public Safety, testified that “as DERs become an increasingly common and significant part of electric and gas service to customers, [the commission] has both the authority and the responsibility to ensure that customers participating in DER markets and programs understand the costs and benefits of their investments and are protected from confusion, fraud and abusive marketing.” (See Comprehensive DER Oversight Best, NYDPS Hears.)

DERs take a broad range of forms, Kelly said, “from rooftop solar panels to smart thermostats, to energy-efficient and demand-responsive industrial equipment, to bio-digesters making energy from farm waste, to community-scale distributed generation projects.”

The order requires residential customers be able to cancel a contract within three business days after its receipt without charge or penalty, and that the contract include essential information about pricing, cancellation rules, tax incentives, and details of the product or service provided.

PSC Chair John Rhodes said the order “provides a thoughtful and protective balance for New Yorkers and the timing is right. We are facing important and welcome growth in these resources, and we need to be in a position to provide protection for customers against untoward practices while pragmatically not burdening developers. I also find the initial focus on [community distributed generation] and mass market [distributed generation] makes all the sense in the world.”

Penalties for a violation of the rules can range from a warning up to a ban from participation in any programs or markets authorized by the commission.

Reining in ESCOs

The PSC also said Brooklyn-based energy service company (ESCO) MPower Energy could be barred from operating in New York following more than 100 customer allegations of deceptive sales and marketing practices.

After investigating complaints dating back to 2015, the commission said MPower must justify within 30 days why it should be allowed to continue operating in the state. The PSC also gave the firm seven days to show why it should be permitted to serve low-income customers, whom the commission said are frequently the victims of aggressive and misleading sales practices by ESCOs. (See NYPSC Limits ESCO Service, Sets New DER Compensation.)

The commission also determined that three ESCOs — Just Energy NY, National Fuel Resources and Zone One Energy — can continue serving low-income customers, while it denied waiver requests for four others: Agway Energy Services, Stream Energy, South Bay Energy and New Wave Energy.

The PSC in December 2016 banned most ESCOs from serving low-income customers but said it would consider waivers for any company that promised to offer bill savings or that could guarantee benefits to those customers. A state court earlier this year issued a temporary restraining order on the ESCO ban, which has been since lifted. (See Court Blocks NYPSC Order Barring ESCO Contracts.)

‘Yes’ to Community Choice Aggregation

The PSC approved the nonprofit Municipal Electric and Gas Alliance (MEGA) to implement a community choice aggregation (CCA) program for several Upstate New York municipalities.

Under the order, additional municipalities will be allowed to form such programs in the future, which “enable communities to take greater control of their energy choices through a transparent and competitive process driven by the consumers themselves,” Rhodes said.

Commissioner Diane Burman asked whether CCAs were subject to the just-issued rules for DER. Kelly said they would be if they included a DER component.

Utilities Prepped for Winter

The state’s major energy utilities expect to have adequate fuel supplies on hand for the coming winter, the commission heard.

“Each utility has a unique mix of assets to serve a unique mix of customers,” said Cynthia McCarran, PSC deputy director for natural gas and water. In her winter preparedness report, McCarran highlighted the efforts by some utilities, notably Consolidated Edison and New York State Electric and Gas, to focus on using demand response programs and so-called “non-pipes alternatives” to meet growing space and water heating needs.

“We anticipate energy consumers will benefit from adequate capacity and supply if we see a harsher-than-expected season,” Rhodes said.

The report said that natural gas bills in general are projected to be slightly higher this winter than historical averages and compared to last winter, which was warmer than normal. On the electric side, this winter’s commodity prices statewide are projected to be slightly higher than last winter, but significantly lower than the historical average.

Commission staff reported that major dual-fuel generation owners are continuing to follow the lessons learned from the harsh 2013-14 winter, including topping off fuel oil storage tanks ahead of the season, making firm arrangements for fuel oil replenishment, and ensuring that plant equipment has been prepared for winter operations.

“The electric utilities have continued to perform well in reducing the electric supply price volatility of their full service residential customers,” McCarran said. “The utilities have hedged approximately 70% of their estimated statewide full service residential energy needs to protect against unexpected electric market price swings that could occur this winter.”

October 23, 2017

FERC Sees Discrepancies in MISO GIA Rules

By Amanda Durish Cook

FERC last week opened a Section 206 investigation into inconsistencies in MISO’s Tariff after re-examining the 2016 termination of a North Dakota wind farm’s generator interconnection agreement (GIA).

MISO FERC GIAs Section 206 — | *EDF Renewables*

The commission on Thursday said MISO’s rules may not be just and reasonable because of discrepancies between the generator interconnection procedures outlined in the RTO’s Tariff and its pro forma GIA. It required MISO and interested parties to file briefs for a paper hearing (EL17-18). FERC expects to render a final decision in June and issued an Oct. 19 refund date.

The commission’s concern centers on a pre-2012 provision in the generator interconnection procedures that allowed an interconnection customer to extend its commercial operation date by up to three years without losing its position in the interconnection queue if MISO found that the extension would not adversely impact lower-queued customers. The provision was narrowed in 2012 so that once entering the definitive planning phase, MISO only allowed the three-year extension if it was caused by a change in milestones by another party to the GIA or a change in a higher-queued interconnection request.

MISO added a third provision for study delays in 2016. At the time, FERC said, “MISO’s proposal to limit the types of changes permissible in the definitive planning phase is consistent with the need to ensure that a project that enters the definitive planning phase is ‘definitive.’”

However, MISO’s GIA was never edited to add the three conditions for a three-year extension and “effectively provides interconnection customers an ability to extend their [commercial operation date] by three years before MISO can seek to terminate a GIA,” according to the commission.

FERC pointed out that MISO has cited the three-year limit in its generator interconnection procedures when terminating GIAs and said the RTO’s latitude to terminate GIAs is “permissive in nature.” The commission also said MISO’s outright termination of GIAs based on the three-year condition ignores its material modification analysis process, which is triggered when an interconnection project experiences changes that affect cost or in-service timing.

FERC said MISO’s interconnection procedures should be revised to reference its GIA and “allow that once a GIA is executed or filed unexecuted, a three-year period from the [commercial operation date] should lapse before MISO seeks to terminate the GIA.”

The issue was initially raised by EDF Renewables subsidiary and wind developer Merricourt Power Partners, which contested FERC’s acceptance of a MISO notice of termination of a GIA entered into by enXco Development and subsequently assigned to Merricourt. (See FERC Upholds MISO Cancellation of GIA.) At that point, the 75-turbine, 150-MW Merricourt wind project in North Dakota had missed its Dec. 1, 2012, commercial operation date by more than three years.

In seeking rehearing of the decision, Merricourt had argued that the commission erred by relying on MISO’s generator interconnection procedures alone and not considering language in the GIA.

FERC ultimately denied Merricourt’s request for rehearing of the termination, saying that MISO’s generator interconnection procedures don’t allow the three-year-plus commercial operation date extension the company sought, even considering “factors beyond the plain language” (ER16-471-001). The commission also said that it could not consider MISO’s study delay provision for Merricourt because it wasn’t yet active at the time the company missed its operating date.

FERC Commissioner Cheryl LaFleur issued a concurring statement, saying the investigation would provide “needed clarity to MISO and interconnection customers regarding their respective obligations going forward.” LaFleur was the sole dissent in FERC’s first decision to cancel the GIA, saying it could create barriers for other wind projects.

“I concur in the decision to deny Merricourt’s requested relief at this time. While I would have granted that relief in March 2016, it is now over a year and a half later, past even the Sept. 30, 2017, [commercial operation date] extension date sought by Merricourt. I do not see a basis to grant rehearing at this point,” LaFleur said.

EDF is still working to secure permitting from the North Dakota Public Service Commission for the project.