Page 1307 – RTO Insider

March 31, 2017

CAISO to Create New TAC Area for Water District

By Robert Mullin

CAISO is seeking to create a new transmission access charge (TAC) area for a California load-serving entity that does not intend to become a participating transmission owner in the ISO.

The “one-off” proposal with the Metropolitan Water District of Southern California (MWD) would create an unorthodox relationship between the CAISO and an important transmission provider that seeks to retain rights over its own network, while also protecting the ISO’s access to key delivery points along the California-Nevada border.

transmission access charge area caiso — CAISO’s proposed new TAC area would cover the transmission system the Metropolitan Water District uses to feed pump stations used to move water from the Colorado River Aqueduct into Southern California. | *CAISO*

MWD delivers water to 26 member agencies serving 19 million consumers in six Southern California counties. It owns about 300 miles of 230-kV transmission lines that feed five pumping plants moving water from the Colorado River Aqueduct and State Water Project into Southern California. At full power, the pumps consume 300 MW of load, which is served by the agency’s share of output from the Hoover and Parker dams.

Edison Agreement Ending

Southern California Edison has been operating MWD’s transmission under a decades-long agreement that predates the existence of the ISO. SoCalEd has declined to renew the agreement when it expires Sept. 30 because of the utility’s reduced allocations from the Hoover Dam.

As a result, MWD is seeking a similar arrangement with CAISO allowing it to preserve its transmission operating rights (TORs) while continuing to offload responsibility for operating its grid. The ISO late last year agreed to act as the water agency’s transmission planning coordinator in matters related to meeting NERC reliability requirements.

While MWD’s generating assets sit outside CAISO’s balancing authority area, its agreement with SoCalEd has firmly integrated the agency’s transmission network into the ISO’s operations. It has allowed the utility to take advantage of MWD’s regulation, ramping capability and capacity reserves. The utility has, in turn, used its own baseload resources to serve MWD’s 24/7 pump loads at a flat rate.

The agreement also requires MWD to turn over its excess transmission capacity to SoCalEd — and now CAISO — for market use. That last point is especially important, because MWD’s transmission broadens the ISO’s access to the key Mead wheeling point out of Nevada and provides the ISO market its only access to the Parker delivery point.

“The ISO has been working with MWD on an operations agreement, which is what we typically do with entities inside the ISO [balancing authority area] that are nonparticipating TOs, but still have a substantial system within the ISO,” Deb Le Vine, CAISO director of infrastructure contracts and management, said during a March 28 call to discuss the issue.

Self Sufficient

As Le Vine explained, MWD is positioned to interact with the ISO as a nonparticipating TO because of its self-sufficiency: The agency can completely serve its load with its own generation and transmission.

“MWD does not lean on the CAISO system at all,” Le Vine said. “They have sufficient generation to meet the [California Energy Commission’s] resource adequacy requirements.”

And the ISO will derive a key benefit from continued integration with MWD. “They are going to still let us use their excess transmission,” Le Vine said.

MWD does have an alternative to being required to join CAISO as a full member. It could instead turn control of its assets over to the Western Area Power Administration’s Lower Colorado balancing area, which would narrow the reach of the ISO’s market.

“We’d stay at Mead, but only with Southern California Edison’s transmission,” Le Vine said. “We would no longer have access to Parker. We’d no longer have MWD’s parallel transmission line [out of Nevada] and the ability to use their transmission.”

Resource Adequacy Requirements

The need to create a new TAC area for MWD is based on an “unfortunate” technicality rooted in the link between California’s resource adequacy (RA) requirements and the ISO’s TAC areas, according to Le Vine. In adopting the state’s RA framework, the ISO chose to use TAC areas as the basis for allocating requirements among LSEs.

“We just need to create this TAC area to account for [MWD’s] load-serving entity obligations separately from how they’ve been accounted for in the past, which was all part of the Edison arrangement under the existing contract,” said John Anders, CAISO assistant general counsel.

Creation of the area will allow MWD to cover the resource adequacy requirements for powering its pumps along the Colorado River Aqueduct system.

“Are they going to pay the same TAC that load everywhere else pays?” asked Susan Schneider of Phoenix Consulting.

“No, MWD has TORs,” replied Le Vine. “They own their own transmission system, so they have never paid the TAC since 1998,” when the ISO began operations.

Eric Little, manager of wholesale market and greenhouse gas market design with SoCalEd, asked if the ISO expected MWD to serve a “significant portion” of its RA requirement with its own pumping load, which can provide system RA in a demand response capacity. Little noted that CAISO’s Tariff exempts participating load from ISO penalties meant to guarantee the availability of resources. Entities that enter a participating load agreement with the ISO are entitled to self-supply to meet their requirements.

“Which means that if they were to use a significant portion of their pumping load to serve as their RA, they would meet RA without having a similar obligation as others because they wouldn’t be penalized if they didn’t meet the obligation,” Little said.

“Well, that’s a decision for MWD to make, and they’d need to be consistent with what’s in the ISO Tariff,” Le Vine said.

“I don’t think there is any other load-serving entity out there that is in that same boat,” Little said. “I think everybody else, if they’ve got participating load, [pumping load] is a very small proportion of their load.”

Le Vine disagreed.

“There’s a very large entity that has a significant amount of participating load that is pumping load that uses that as RA,” she countered, referring to the California Department of Water Resources.

“It’s concerning, but I guess that ship has already sailed,” Little responded.

CAISO wants stakeholders to submit comments on the proposal to create the MWD TAC area by April 11, and expects to seek Board of Governors approval on the measure in May.

March 31, 2017

Texas PUC Puts Brakes on NextEra’s Oncor Acquisition

By Tom Kleckner

The Public Utility Commission of Texas unanimously agreed Thursday that NextEra Energy’s proposed $18.7 billion acquisition of Texas utility Oncor is not “at this point” in the public interest.

Chairman Donna Nelson and Commissioner Ken Anderson both read prepared statements into the record during a PUC open meeting. They cited the need for strong ring-fencing provisions that would include an independent board of directors for Oncor — a requirement NextEra has called a “deal-killer.”

“The tangible benefits to this transaction are few,” Nelson said. “In order to find this in the public interest, I would need to keep those ring-fencing provisions in place.”

“Bottom line, I do not find the tangible and quantifiable benefits are an improvement over the status quo to justify approval” of the deal, Anderson said, reading from a memo he later filed (Docket 46238). “To be honest, it has to do with their deal-killers.”

Commissioner Brandy Marty Marquez agreed with Anderson, saying she took NextEra “at its word” and complimented the company on its candor in the proceeding.

“I don’t believe they were posturing,” she said. “They were telling us quite clearly what they could and could not live with. I’m not happy to say that those were, unfortunately, the things I feel like we should not bend on.”

PUC staff will now draft a preliminary order that the commissioners can adopt during their April 13 open meeting.

Next Step Unclear

Whether this ends NextEra’s bid to acquire Oncor — which the Florida-based company has eyed for several years — remains to be seen. NextEra and Oncor representatives were not given an opportunity to appear before the PUC on Thursday, and both companies declined to comment on the commissioners’ remarks or next steps.

A previous attempt to acquire Oncor, by Dallas-based Hunt Consolidated, ended last May when Hunt withdrew its yearlong application over PUC requirements it found too onerous. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)

Hunt officials would not say Thursday whether they hope to make another bid.

“We have a long-standing policy of not commenting on other parties’ regulatory proceedings,” said Hunt spokesperson Jeanne Phillips in a written statement. “We are watching these events with interest and will wait for the commission’s final vote.”

Oncor has long been considered the crown jewel of Energy Future Holdings’ assets. EFH — previously TXU Corp. before being acquired by private-equity firms in a leveraged buyout — declared Chapter 11 bankruptcy in 2014 and has since spun off its generation and retail electric service providers as part of Vistra Energy.

Board Independence Issue

The utility has been ring-fenced since the 2007 buyout. That helped insulate Oncor from much of the $45 billion in debt EFH had incurred when it declared bankruptcy.

“The lack of a truly independent disinterested board and the lack of independent board control over the dividends are what worry me the most,” Nelson said. “And unfortunately, those are the issues on which it seems NextEra Energy is not willing to budge.”

During a public hearing in February, NextEra told the PUC it needs to maintain control over Oncor’s board to ensure its ability to appoint or remove the utility’s directors. The company said that is a fair trade-off for lending its A- credit rating and $59.2 billion market capitalization to help Oncor eliminate debt left by EFH. (See Hearings Over, PUCT, NextEra Ponder Oncor ‘Deal-Killers’.)

In its most recent filing, NextEra said its proposed ring fence retains virtually all of the 2007 conditions, while adding additional protections “that would not impede consolidation of NextEra Energy’s and Oncor’s credit profiles.”

The company noted it is proposing “a comprehensive suite of 73 regulatory commitments,” some in response to staff and intervenor concerns.

“These regulatory commitments offer substantial protections and benefits for Oncor and its customers and are more than sufficient to protect Oncor and its customers from any perceived risks associated with NextEra Energy’s ownership of Oncor,” NextEra said.

Nelson also referenced a July 2016 ratings report from Moody’s Investor Service. She quoted the report as saying “the acquisition-related debt without a material amount of deleveraging would exhaust NextEra Energy’s debt capacity at its current rating” and “makes the company more vulnerable to unforeseen events or margin shortfalls.”

NextEra told the PUC in February it has $12.2 billion reserved for funding the transaction — $9.8 billion for an 80% interest in Oncor and $2.4 billion for a 20% interest in various holding companies. It would assume the remaining $6.5 billion in debt, in line with its 60/40 debt-to-equity ratio.

“I worry about removing the ring-fence protections in this situation, where the debt above Oncor isn’t being extinguished, but is instead being refinanced with new debt at NextEra Capital Holdings,” Nelson said. “The parent company will remain substantially leveraged in order to make the purchase happen.”

“I see as much downside as upside to linking Oncor’s credit rating to NextEra Energy,” Anderson said. “I would require staff’s version of the condition de-linking the respective credit ratings … but given that they are all also NextEra Energy deal-killers, it seems to me that we would be wasting time and resources to proceed further down the road of appearing to approve the transactions with such conditions.”

March 31, 2017

PJM Stakeholders Explore Price Formation, Seek Transparency

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM should explain its daily operating decisions in more detail so market participants can better understand how markets are formed, stakeholders told staff at Tuesday’s special session of the Market Implementation Committee.

PJM price formation security constrained economic dispatch — Greiner | © *RTO Insider*

Bruce Bleiweis of DC Energy went so far as to request that PJM produce “an actual document” that enunciates all of its processes.

“If there are things that PJM doesn’t publicly want to post, doing it under the [Critical Energy Infrastructure Information] protocol should be sufficient,” he said.

Chantal Hendrzak, who chairs the MIC, said that her staff at PJM will “take that back and see what we can come up with.”

Part of the concern for stakeholders is that PJM gives its system operators discretion to analyze data and make decisions on the fly. While this keeps the system flexible, stakeholders said it also makes understanding the RTO’s thought processes more opaque.

“I think the first order of priority ought to be [finding out] what information [PJM can share] to understand what’s going on on the system,” one stakeholder said. He clarified that part of his interest was looking back to determine what caused uplift on the system.

PJM’s Keyur Patel, who gave a presentation on the RTO’s day-ahead market clearing process, pointed out that PJM will dispatch between 1,200 and 1,500 generation units on a typical day, and only 10 to 15 units will change throughout the day.

“There are times where we do want to make some commitment changes, but we run out of time and at those times, it’s better to post results on time than to change one unit,” he said.

Additionally, some decisions are made by the mathematic calculations of PJM’s security constrained economic dispatch (SCED) system without human intervention, said PJM’s Joe Ciabattoni, who gave a presentation on the RTO’s dispatch process.

There are times when “the engine cannot solve the problem in the time parameters it’s given. [It will] sacrifice one constraint to get power balance and retain control for the rest of the system,” he said. “We need a solution every three to five minutes to maintain system control.”

In that case, the system relaxes its constraints to allow the system to solve.

Ciabattoni explained it as his “but-for logic,” in that certain units wouldn’t have been committed but for a specific constraint.

“To unravel every one of those little variables … would need a team to determine them all,” he said. “But we could use: ‘but for that constraint, we wouldn’t have committed these [theoretical] 500 MW.’”

PJM’s perfect dispatch analysis evaluates all commitments, but only after the fact when the RTO knows what flow actually transpired, he said.

Ciabattoni said PJM doesn’t have any ramping issues for wind or solar “like other RTOs do,” except on extremely cold mornings.

An issue to consider, he said, is that once a unit is brought on, the constraint may go away because that unit overwhelms the constraint, but it may return if the unit is turned off.

“When SCED is looking at a solution … it may be getting fractional megawatts from a bunch of units,” Ciabattoni said, or a unit’s economic minimum output may be so close to its economic maximum output that it can’t cycle up or down efficiently. If such a unit is left running, there will be hours where it sets price and hours where it does not. When It doesn’t, it will create uplift, he said.

Joel Luna of Monitoring Analytics, the firm that serves as PJM’s Independent Market Monitor, said uplift comes down to three factors: megawatt-hours, LMP and the unit’s offer price.

The session resulted from a problem statement approved by stakeholders in January. (See “Work on Uplift Moves Forward Despite NOPR,” PJM Markets and Reliability and Members Committees Briefs.)

By the end of the meeting, the special session’s facilitator, PJM’s Rami Dirani, determined that stakeholders needed more education before a useful list of interests for the group could be determined. He decided to cancel the group’s next meeting on April 5 and proceed with more education at its following meeting on April 25.

March 31, 2017

PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will

By Rory D. Sweeney

PJM can maintain adequate reliability with a generation fleet almost entirely composed of natural gas units, but a capacity mix of more than 20% of solar would unacceptably increase the risk of loss-of-load events, according to a study the RTO released Thursday.

The study, titled “PJM’s Evolving Resource Mix and System Reliability,” identified essential reliability and adequacy criteria and used them to compare a wide range of potential future fuel diversity scenarios. PJM focused on generator “reliability attributes” of frequency response, voltage control, ramping ability, fuel assurance and flexibility.

PJM created a “composite reliability index” to assess the operational reliability of various resources under four conditions: normal peak conditions, light load, extremely hot weather and extremely cold weather. Resources were grouped into 11 categories: coal, natural gas steam, natural gas combustion turbine, oil steam, oil combustion turbine, nuclear, solar, wind, hydro, battery/storage and demand response.

The RTO said the report is in response to stakeholder concerns that the system is losing too many traditional baseload resources as coal plants retire and nuclear assets struggle to remain profitable.

In 2016, PJM’s installed capacity was 33% coal, 33% natural gas, 18% nuclear and 6% renewables, which include hydro. By comparison, coal and nuclear resources accounted for 91% of its generation fleet in 2005.

“This analysis underscores our responsibility to continue to operate the system reliably, and explore the role of resilience, the ability to tolerate unforeseen shocks and continue to deliver electricity,” PJM CEO Andy Ott said in a statement. “Different resources provide different reliability attributes, though new technology or regulations have the ability to improve those capabilities.”

No Upper Bound on Gas

Of particular interest, given the rise in gas-fired units interconnecting to PJM’s system, was the revelation that the there was no upper bound for the percentage of gas-fired units in the fleet before reliability is harmed.

The scenarios showed natural gas’ share of the fuel mix could rise to as high as 86% without reliability problems. Mike Bryson, PJM’s ‎vice president of system operations, who spoke during a press briefing on the report, said staff stopped at 86% to account for demand response, hydropower and biomass currently on the system. “We figured it was a safe assumption to say they won’t go away.”

The report acknowledged, however, that it didn’t assess the gas-deliverability issues that pinched supply during January 2014 or the continued sluggishness of gas pipeline development. PJM’s previous natural gas studies generally concluded that the existing and planned pipeline infrastructure would be adequate for current and future anticipated electric system needs.

“We did not look at ability for infrastructure to support that, but we think it’s probably worthy of following up with the natural gas industry,” Bryson said. “There’s a lot of work left to do.”

The report also didn’t address the economics of resource types, factors that might impact a fuel’s deliverability or public policy issues such as environmental impacts or the use of subsidies. Bryson suggested coordination with the gas industry to begin addressing “more complicated issues” that cross over from the electricity sector, including data coordination.

That said, the report found that PJM’s current and near-term fuel mixes were near the top of the study’s reliability analyses. Less coal and nuclear generation would decrease frequency response, reactive capability and fuel assurance, but increase flexibility and ramping capabilities.

Renewables Limits

Portfolios with solar representing 20% or more of unforced capacity (UCAP) failed because they resulted in loss-of-load-expectation (LOLE) violations at night. UCAP is calculated by multiplying nameplate capacity by the resource’s capacity factor (38% for solar).

Bryson said increases in batteries and other storage would likely change the conclusions.

He added that certain fuel types were given credit for their abilities, if not their current usages. “We gave wind kind of high marks on flexibility, even though that’s not how they operate today,” he said. “The capability’s clearly there, but they don’t operate in that way.”

Fuel Diversity ≠ Reliability

The study also found that a more diverse fuel portfolio isn’t necessarily more reliable. Certain resource blends that fall between the least and most diverse offer the greatest number of key generator reliability attributes.

“Having a certain amount of diversity — not too much, not too little — gives you optimal reliability,” said PJM’s Chantal Hendrzak, who also spoke at the briefing.

However, high reliance on one type, such as gas, would create concerns that the paper didn’t attempt to analyze. PJM said it would continue to investigate ways to minimize its exposure to “low-probability, high-impact” events that could pose serious threats to the system.

“Our markets are designed to provide the incentives that the [13] states [within PJM’s footprint] need to implement their policies. We think there is an opportunity for PJM to work with the states” to determine how to harmonize well-functioning markets and public-policy initiatives, Bryson said.

The topic of reliability will be the focus of PJM’s upcoming Grid 20/20 conference scheduled for April 19.

March 30, 2017

Kentucky Overturns Nuclear Moratorium: Now What?

By Amanda Durish Cook

Kentucky has dropped its decades-long nuclear moratorium, but experts on both sides of the nuclear debate say the move probably won’t result in new reactors for now.

The law, signed by Kentucky Gov. Matt Bevin on March 27, eliminates the requirement that nuclear power facilities have “means of permanent disposal” of nuclear waste, allowing a less onerous Nuclear Regulatory Commission-approved waste plan.

Sen. Danny Carroll (R), the bill’s sponsor, said it was important that Kentucky start looking to diversify its energy portfolio, pointing out that nearby states take advantage of nuclear energy. Carroll said the law will “keep Kentucky competitive with the energy portfolios of surrounding states.”

“When you run a business, you look for varied funding streams. You don’t put all your eggs in one basket. … That’s what we’re doing in our state. Out of fear of nuclear energy, out of efforts to protect the coal industry, whatever the case may be, we are putting all our eggs in one basket,” Carroll said last year, when an earlier version of the bill languished after Senate approval. Kentucky does not house any nuclear generation.

The law eliminates the requirements that cost of waste disposal be known and that the facility have “adequate capacity to contain waste.” It also grants the Kentucky Public Service Commission the authority to hire consultants “to perform duties relating to nuclear facility certification” and allows it to prohibit construction of low-level nuclear waste disposal sites in Kentucky. The PSC can also direct the Energy and Environment Cabinet to review the nuclear permitting process. Kentucky PSC Director of Communications Andrew Melnykovych declined to comment on the law.

14 States

According to the National Conference of State Legislatures, 14 states currently have restrictions on the construction of new nuclear power plants: California, Connecticut, Hawaii, Illinois, Maine, Massachusetts, Minnesota, Montana, New Jersey, New York, Oregon, Rhode Island, Vermont and West Virginia. Most of the state moratoriums were made because of an absence of a permanent repository for spent fuel in the U.S. Wisconsin’s legislature ended its moratorium last spring.

President Obama ordered NRC in 2009 to stop work on a permit for licensing the nuclear waste depository at Yucca Mountain in Nevada. Obama acted at the behest of then-Sen. Harry Reid (D-Nev.) As a result, waste is being stored in spent-fuel pools and dry cask storage at operating and retired nuclear plants. (See Panelists Weigh Nuclear Waste Solution Post-Obama.)

The Trump administration’s 2018 budget requests $120 million to relicense Yucca Mountain.

Christine Csizmadia, the Nuclear Energy Institute’s director of state governmental affairs and advocacy, said she shared Carroll’s idea that long-term energy planning should not exclude certain generation types.

“You want to have an open option on the table, and that’s something that they couldn’t even consider before,” Csizmadia said. “It’s going to open the door to healthier conversations because now lawmakers aren’t confined and they can have long-term, open conversations.”

Csizmadia said that although she does not envision new nuclear building permits in Kentucky in the near term, she hopes Wisconsin’s and Kentucky’s actions will spark a trend. “That’s exactly what we’re hoping for, and why not? The thing about states is that they can be very competitive with each other; there’s a snowball effect. I don’t see why there wouldn’t be similar repeals. A lot of these moratoriums were made 20 years ago, and attitudes have changed.”

Nuclear Power a Distraction

Not everyone’s attitude toward nuclear energy has changed, however.

“Lifting the nuclear moratorium is not going to produce plants. Nuclear is such a politically charged question that it sucks all of the air out the room when planning,” said Arjun Makhijani, president of the Institute for Energy and Environmental Research, who has testified against overturning Minnesota’s nuclear moratorium. Minnesota’s legislature came close in the 2015/16 legislative session.

Far from opening up planning to new resource types, Makhijani said the moratorium reversal could shut down other, more important energy planning conversations.

“The main result is it’s going to divert the attention of Kentuckians away from the kind of energy policy that will be useful to create jobs in the state,” Makhijani said. “In a state that is hurting from coal industry job losses [the idea that] there are plans to replace those jobs with the nuclear industry — the most polite thing that I can say is that it’s very far-fetched. The idea is that we should have all options [but] the options have to make sense in economic terms and in planning terms. We’re entering the era of distributed energy and smart grids.”

Makhijani argues that the country’s aging nuclear fleet is often in need of repairs, requiring new valves and pumps and expensive shutdowns. He noted that nuclear plants cannot economically ramp up and down, making them too inflexible to be paired with increased wind penetration.

“I think the suffering communities in Kentucky, the coal miners, should be economically protected. But I don’t think they can be protected by promising a return of coal jobs or replacing it with nuclear industry. Nuclear is more expensive and less economic than coal. Nuclear is sort of in hospice care right now,” he said.

Summer, Vogtle Plants

Csizmadia and NEI spokesman John Keely said they did not know of any sites in Kentucky that have been eyed for nuclear development. But Keely said nuclear power can help fill the need for clean energy as coal plants retire.

Nuclear power is being revived, he said, with two new reactors being built by South Carolina Electric & Gas at its Virgil C. Summer nuclear plant near Jenkinsville, S.C., and two by Georgia Power at its Vogtle site near Augusta.

Virgil C. Summer Nuclear Plant Construction | *SG&E*

However, Makhijani said these new reactors are being subsidized by ratepayers and plagued by cost overruns and delays. “It’s even unclear whether those reactors will be finished,” he said, alluding to U.S. nuclear giant Westinghouse Electric’s bankruptcy filing Wednesday. Westinghouse is the lead contractor at both construction sites.

Makhijani also cautions against seeing small modular reactors as an option, saying they won’t be cost effective unless large numbers of them are purchased, and even then, several of them will need to be installed to generate a significant amount of power.

Still, a permanent repository is needed no matter how many more states light up a welcome sign for nuclear energy, Makhijani said. But he maintains that Yucca Mountain is not the ideal site.

“It’s much better than leaving it around in five dozen or odd sites in storage. There are terrorism risks, there are environmental risks, there are safety risks,” he said. Each 1,000-MW nuclear reactor results in 30 Nagasaki-sized bombs worth of plutonium per year in spent fuel, Makhijani said. “Today there is more civilian-made nuclear waste around than all the plutonium of all of the nuclear weapons worldwide,” he added.

Keely maintains that nuclear moratoriums “were a manifestation of the 60s’ anti-nuclear attitude … and can’t be defended anymore. It’s that basic and that pragmatic.”

He also said today nuclear has bipartisan support. “This used to be somewhat of a left-right issue and that’s no longer the case.”

March 30, 2017

New Campaign Urges Renewed Effort to Expand CAISO

By Robert Mullin

A coalition of environmental, renewable energy and business groups called on California officials Tuesday to reignite CAISO’s effort to expand its operations into other areas of the West.

The groups — which include the Natural Resources Defense Council, Environmental Entrepreneurs, Union of Concerned Scientists and the Solar Energy Industries Association — issued a letter urging Gov. Jerry Brown and top state lawmakers to support legislation facilitating the ISO’s transition into a Western RTO.

“An integrated Western Grid is essential to a goal that we know all of you share: meeting our ambitious clean energy targets while driving down energy costs and creating new good-paying jobs,” the letter said. “We urge you to continue the process toward legislative authorization of a transition to a fully independent board for an independent grid operator that all Western utilities and generators will have the opportunity to join.”

The coalition kicked off its Secure California’s Energy Future campaign in response to the Trump administration’s move to roll back the Clean Power Plan, EPA’s chief initiative to combat climate change by reducing carbon emissions from the nation’s power plants. (See Trump Begins Attempt to Undo Clean Power Plan.)

“California has an opportunity — and a responsibility — to continue its leadership in responding to our climate crisis by working to integrate the Western grid,” Ralph Cavanagh, codirector of NRDC’s energy program, said in a statement. “While the White House and some in Congress are trying to roll back the climate progress we’ve made, Sacramento can take action and secure California’s energy future.”

Reduced Costs, Increased Reliability

The campaign’s supporters contend that integration of the Western grid would reduce costs and increase reliability for the region’s electricity customers, reduce the need to curtail output from renewable resources and “safeguard against price gouging by unscrupulous power marketers,” while at the same time allowing state governments to retain control over their energy policies. They also tout the benefits to California’s economy, including expansion of the state’s clean technology sector.

“Every day, California is basking in clean, affordable, reliable solar electricity,” SEIA CEO Abigail Ross Hopper said. “By enabling the state to fully utilize this solar resource, including sharing it across state lines, Californians will reap the benefits of increased jobs and investment and billions of dollars in electricity savings.”

A 2015 California law requires the grid operator and state energy agencies to explore ISO expansion to help the state meet its 50% renewable energy mandate. California lawmakers must sign off on any such expansion, which would necessitate that the state yield its direct oversight authority over CAISO once the grid operator becomes a multistate organization.

Brown Presses Pause Button

With skepticism mounting against regionalization efforts, Brown last August postponed CAISO’s expansion effort, saying he wanted state agencies to take more time to develop a governance proposal for the new RTO. (See Governor Delays CAISO Regionalization Effort.) Before that announcement, Brown had expressed hopes of delivering a proposal to state lawmakers before they concluded their 2016 session in September.

Progress on regionalization has since slowed. While the ISO last October released the third draft of a proposal outlining the principles for governing a Western RTO, nothing formal has been submitted to the legislature for consideration. (See Latest CAISO Proposal Fills out Western RTO Governance Plan.)

“We continue to be involved in discussions with stakeholders, and we get requests for briefings from lawmakers about the studies” related to the economic and environmental impacts of regionalization, CAISO spokesperson Anne Gonzales told RTO Insider. “The ISO is a technical resource for policymakers to understand the studies and the governance changes.”

Gonzales said the ISO has no stakeholder meetings scheduled to further discuss regionalization.

Agreement on a governance plan represents the biggest hurdle for expanding CAISO. Skeptics outside California have expressed concerns about the populous state’s potentially outsized influence over a Western RTO, while those within California are worried about losing the ISO as a key instrument for achieving the state’s environmental goals. (See Governance Plan Critics Urge Slowdown of Western RTO Development.)

The new campaign appears to be an attempt to jump-start the effort to overcome barriers to grid integration.

Other campaign supporters include the Independent Energy Producers Association, Bay Area Council, Health Care Without Harm, Sierra Business Council, Silicon Valley Leadership Group and SunPower.

March 30, 2017

Mountain West, SPP Tout RTO Membership to Colo. PUC

By Tom Kleckner

DENVER — SPP and the Mountain West Transmission Group pitched the benefits of RTO membership Tuesday in an open forum before Colorado’s Public Utilities Commission as the two entities pursue a possible collaboration.

Taking advantage of the opportunity to get the last words in, SPP COO Carl Monroe grabbed a podium microphone just before the meeting adjourned to let his audience know the RTO would be holding its regular quarterly governance meetings in Denver in July, and that it would be a chance to see first-hand how SPP works with its members.

Coincidence?

Maybe not. SPP scheduled the meetings in the middle of last year, about the same time Mountain West was considering joining CAISO, MISO, PJM or SPP. Mountain West announced in January it was entering into discussions with SPP to further explore the relationship. (See Mountain West to Explore Joining SPP.)

The PUC scheduled the forum so regulators, consumer advocates and other stakeholders could gather information and discuss with Mountain West participants the potential benefits, costs and risks of the options under consideration. More than 70 attendees registered to participate, a number Commissioner Frances Koncilja noted was larger than normal.

Mountain West is an informal collaboration of 10 electricity service providers serving 6.4 million customers in the Rocky Mountains. Its members’ coincident peaks total just more than 12 GW, and it generated almost 70 million MWh of energy in 2015. Were it to join SPP, it would create a sprawling organization spread over 17 states.

Monroe told the commission that Mountain West would increase SPP’s size (575,000 square miles of service territory encompassing about 18 million people) by about a third. The new RTO’s Tariff would include seven of the eight DC ties between the Eastern and Western Interconnections, except for one in Canada. SPP also has two DC ties with the Texas Interconnection.

“We own the gateway facilities that go into” the ties, Monroe said. “We’ve spent a lot of time coordinating and understand those ties.”

“This is a very complicated transaction,” Koncilja told RTO Insider. “It will be up to the utilities to persuade us it’s a good thing for the ratepayers. This is just the first of many meetings.”

Mountain West members said they were pursing RTO membership to improve efficiency by eliminating pancake transmission rates and taking advantage of modern market designs to maximize transmission capacity. A 2016 Brattle Group study found Mountain West could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with a single one.

“It’s not that we have decided to go forward,” said Steve Beuning, Xcel Energy’s director of market operations. “We are in the process of evaluating what it means to go forward and [determining] the terms and conditions … that Mountain West considers essential before moving forward.”

Familiarity

Beuning said he was impressed by the knowledge in the group’s proposed RTO membership.

“This familiarity with the issues of our proposal, and an understanding of the particular needs of utility service providers in the western U.S., really helped lead to a deep and meaningful discussion,” he said.

Former FERC Commissioner Suedeen Kelly, an attorney with Akin Gump provided an overview of RTOs and ISOs, their functions and their regulatory relationship with FERC, while touting the virtues of regionalization and economic dispatch.

Former FERC Commissioner Suedeen Kelly (right) shares her thoughts on Mountain West’s SPP membership with Colorado PUC Chairman Jeff Ackermann and Commissioner Wendy Moser. | © *RTO Insider*

“The SPP transmission system is managed and operated for the same purpose as an individual system — to maintain reliability across the footprint and to dispatch generation,” she said. “There are no pancaked rates. Energy that flows from the northern end to the southern end pays one rate, no matter how many systems it touches.”

Jennifer Gardner, a staff attorney for Western Resource Advocates, praised SPP’s security constrained economic dispatch and its ability to create more renewable energy.

“By automatically dispatching resources where they’re needed, that allows us to deal with the variability of resources,” she said. “We see the immense potential for getting new renewable energy to the market” with SPP membership.

But Kelly also shared reasons for not joining an RTO.

“Why don’t we have one in the West?” she asked. “A lot of reasons, but to me, the most important, after being in California in 2000 when the California market imploded, is because the market imploded. We said, ‘Wait a minute, whatever they did, we don’t want to do.’”

Abby Briggerman, of counsel with Holland & Hart who generally speaks for large industrial ratepayers in the Rocky Mountains, and speaking on behalf of the ratepayer interests, said she was concerned about the risks of joining an RTO.

“We’ve come a long way since 2001, but we need to look no further than California. We remember the rolling blackouts,” she said. “The ratepayer must have a seat at the table in the decision-making process over whether to join an RTO.”

Briggerman also warned that SPP could be a “Hotel California,” referring to the Eagles’ song in which “you can check out any time you like, but you can never leave.”

“We need to make sure there are no barriers to exit,” she said.

Consumers’ Voice

Other attendees also questioned whether consumer interests would be lost in SPP.

SPP representatives, members and stakeholders countered by praising the RTO’s stakeholder engagement, and Monroe emphasized the diversity of is 94-entity strong membership. “We provide a lot of transparency into SPP,” he said. “Our meetings are open, even up to board level. We had 150 people at our last board meeting. Anybody that has ideas that will help SPP make good business decisions will be listened to.”

SPP General Counsel Paul Suskie brought up Steve Gaw, a former Missouri commissioner and legislator who represents The Wind Coalition at meetings although the coalition is not a member.

SPP COO Carl Monroe makes his point alongside General Counsel Paul Suskie (left). | © *RTO Insider*

“He’s not a member, but he gets just as much input as members,” Suskie said.

SPP and Mountain West have developed a steering committee and working groups focused on governance, rate design and cost allocation, transmission planning, reliability coordination and SPP’s Regional State Committee. Composed of regulators from 10 different states, the RSC will be a key player in the membership negotiations.

Mountain West members said they expect to decide on whether to proceed with SPP membership in the second or third quarter of 2017. Rate cases would be filed shortly thereafter, with a final recommendation presented to SPP’s board in January 2018.

“I would be bold to call [the timeline] aggressive, but it keeps us on track. It keeps us focused on what we’re trying to accomplish,” said Mary Ann Zehr, senior manager of transmission contracts, rates and policy for the Tri-State Generation and Transmission Association.

Mary Ann Zehr (Tri-State), Dan Kline (Black Hills) and Steve Beuning (Xcel Energy) discuss Mountain West’s potential SPP membership. | © *RTO Insider*

Zehr said she anticipates numerous meetings over the next few months devoted to writing a tariff, governance and membership agreements and bylaw changes.

“We’re attempting to answer those questions at the front end,” she said.

March 29, 2017

CAISO, BPA Ink Agreement to Ease Northwest EIM Transfers

By Robert Mullin

CAISO has signed an agreement with the Bonneville Power Administration designed to facilitate Energy Imbalance Market (EIM) transfers in the Pacific Northwest while ensuring that the agency can continue to reliably serve its own transmission customers.

The Coordinated Transmission Agreement (CTA) could provide a model for future joint efforts between the two agencies that operate most of the transmission network along the West Coast, according to Todd Miller, a senior project manager with BPA.

“This agreement kind of seems like a no-brainer,” Miller said during a March 27 call hosted by the EIM Body of State Regulators (BOSR), an informal network of Western utility commissioners that convenes regularly to discuss market issues. “We need to have an operating agreement … so everybody understands the rules of the road.”

The agreement also represents a “milestone” in cooperation between BPA and CAISO, Miller said. “I think it’s really a first step in being able to coordinate seams issues.”

The CTA largely formalizes procedures already put in place before the EIM was launched in November 2014. At the time, BPA worked with PacifiCorp — the EIM’s first member — and the ISO to define practices around exchanging transfer data and setting limits on the use of dynamic transfers on the BPA system.

Since its rollout, the market has expanded farther into the Northwest to include Puget Sound Energy, with Portland General Electric slated to join later this year, followed by Idaho Power in early 2018. All three utilities rely to some extent on BPA, which controls about 70% of the transmission in the region.

“Some of [the original practices were] captured in operating procedures, but until the CTA, there was no contractual obligations regarding these requirements,” BPA said.

The agreement spells out an obligation for both parties to share transmission system data: CAISO must share total market dispatch for EIM resources during a market interval and load forecasts for EIM balancing authority areas, while BPA must convey real-time managed limits and actual flows on its facilities. The agreement clarifies the processes by which that data will be made available, including frequency and granularity.

Bonneville Power Administration caiso eim rate of change limit — The agreement between CAISO and Bonneville Power Administration is intended to facilitate Energy Imbalance Market transfers on Bonneville’s system, which accounts for about 70% of transmission capacity in the Northwest. | *BPA*

“It also includes a confidentiality provision,” Miller said. “Everybody is doing what they’re supposed to be doing, but now there’s something in the contract that makes the lawyers feel better about things.”

The agreement also codifies BPA’s right to place limits on the upward and downward rate of change in usage that EIM dynamic transfers would impose on its transmission network — making explicit an already existing practice.

“Bonneville will set the upper rate of change limit and lower rate of change limit at its discretion and notify the CAISO of such limits for each Bonneville-managed facility before each market interval,” the agreement states.

The agreement gives BPA the ability to manage system operating limits on its paths at its own discretion, but requires it to alert the ISO to any changes ahead of an interval.

It also provides for the development of “flow-relief tools” related to the EIM. Among those tools: a procedure that, in a curtailment situation, will allow BPA to transmit to CAISO the EIM’s prorated share of curtailed flows on an affected transmission flowgate between the two balancing areas.

New Groups

The CTA additionally calls for CAISO and BPA to convene a Coordinating Committee every quarter to address operational issues related to the agreement, resolve disputes and offer up potential revisions.

The agreement also establishes a working group — consisting of Pacific Northwest EIM members, a select group of BPA transmission customers and the Coordinating Committee — charged with discussing implementation, data exchange and transmission operations under the agreement.

“As far as the selected Bonneville customers, we haven’t decided how we’re going to do that yet, but we want to select customers that are representative of our various classes of transmission customers,” Miller said.

Ann Rendahl, a Washington Utilities and Transportation commissioner and chair of the BOSR, noted that the “whereas” clause at the beginning of the CTA specifies that the Coordinating Committee will discuss seams issues.

“I assume that the working group is also to discuss seams issues, but to get at them from a more granular level,” Rendahl said.

Miller agreed and said the group could also be the body that initiates other “major” types of coordination and constraint relief along the interties.

CAISO and BPA plan to file the agreement with FERC in April. “Hopefully we’ll have another FERC commissioner at some point so it can actually be approved,” Miller said.

March 28, 2017

PJM Monitor Says Low Prices Indicate Competitive Market

By Rory D. Sweeney

WILMINGTON, Del. — Independent Market Monitor Joe Bowring said Thursday that that the PJM market is competitive and healthy, despite what some stakeholders believe are uneconomically low energy prices.

state of the market report combined cycle — Bowring, PJM’s IMM, discusses his analysis of market data that he believes shows the market is healthy and competitive. | © *RTO Insider*

LMPs were lower in 2016 than they have ever been since organized markets began, which “is a testament to competitive markets,” Bowring said during a Members Committee briefing on the 2016 State of the Market report. “Prices are not too low. We don’t need to artificially raise prices. They are what they are.”

Despite the market changes created by the introduction of the Capacity Performance model, “prices have been consistent with historical levels,” he said.

Combined cycle units, for example, did “relatively well” in 2016, he said. “Even though their margins are smaller, they are in fact making it up on volume.”

That does, however, create one issue, he said: While combined cycle units have become baseload resources, coal-fired units have shifted to an intermediate role, which is problematic because they can’t ramp up and down well. Coal steam units recorded a 32.5% capacity factor for the year, down sharply from 2015’s 43.8%. Combined cycle plants had a 62% capacity factor in 2016, almost unchanged from 2015.

Generator Markups

Bowring’s presentation focused heavily on the impact of markups, which is the difference between a market seller’s market-based offer and its cost-based offer, which reflects the generator’s marginal costs. The Monitor’s data showed that coal-fired plants often had negative markups in 2015 and 2016.

“I think [the market] is very healthy. I think it’s competitive. I think it’s showing us Manual 15 is wrong, and coal units don’t need a 10%” adder, Bowring said. The manual permits generators’ cost-based offers to include a 10% adder above their marginal costs; it was intended as a cushion against uncertainties, including fuel prices and heat rates that can vary with temperatures and plant loading.

FirstEnergy’s Jim Benchek questioned Bowring’s observation, saying coal units have “really legitimate reasons” for offering negative markups.

Bowring explained that higher markups can be exercises of market power — or an indication that the operators simply don’t want the unit to run. He presented a graph that showed the cumulative number of unit intervals with markups above $150/MWh. The graph showed a major spike in mid-February 2015, which he said coincided with a cold snap that might entice market sellers to exercise market power.

Algorithmic Definition

Bowring also said it’s “staggering to me” that PJM refuses to evaluate fuel-cost policies based on algorithmic standards.

In a ruling Feb. 3, FERC sided with the RTO in requiring that fuel-cost policies be verifiable and systematic but not algorithmic, as the Monitor had proposed. (See PJM Fuel-Cost Policy Changes to Take Effect in May.)

FERC’s order quoted the Monitor as saying the policies should be based on broker quotes, bilateral offers or index prices. The commission said the Monitor’s position that policies be “algorithmic under all circumstances” ignores that natural gas markets can become illiquid during stressed conditions, potentially understating generators’ real costs.

The Monitor said it defines “algorithmic” as simply meaning a step-by-step process to get from a defined input to an output.

“It’s very, very simple, very, very basic,” Bowring said Thursday. “You can’t have a verifiable anything unless it’s algorithmic.”

Bowring also questioned the notion that PJM’s energy production is becoming less fuel diverse, presenting a Fuel Diversity Index that shows little change since its beginning in 2000.

Bowring released the State of the Market report earlier this month, warning that state plans to subsidize unprofitable generating resources present “a very real threat” to wholesale electricity markets. (See PJM Monitor Concerned About State Subsidies.)

March 28, 2017

SPP Briefs

Having concluded that renewable energy is “extremely unlikely” to be exported outside SPP’s footprint, staff have begun working on the Export Pricing Task Force’s final report for delivery in July.

SPP Export Pricing Task Force — Loudenslager | © *RTO Insider*

SPP’s Sam Loudenslager said a market exists for renewable resources, but “rate stress” from building additional transmission and uncertainty that the energy would be deliverable led staff to its conclusion. He also pointed to the difficulties SPP has had in agreeing to joint transmission projects across its seam with MISO.

“It’s not impossible, but it’s difficult,” Loudenslager said.

SPP’s Michael Desselle, the task force’s staff secretary, pointed to a list of proposed market and operational improvements to address renewable resources and advocated for canceling the rest of the group’s scheduled meetings. Members objected, however, and the task force agreed to additional meetings before turning over the final report to the Strategic Planning Committee.

“I don’t think we’re done yet. We haven’t laid out anything that looks at the export issue itself,” said Marguerite Wagner, of independent transmission company ITC Holdings.

The group also discussed creating “national renewable resource areas” to enable wind exports to markets outside SPP and avoid placing the costs directly on the RTO’s members or ratepayers.

Referring to himself as a “big-picture guy,” Golden Spread Electric Cooperative’s Mike Wise, the group’s chair, asked whether the federal government should be involved, as it was in building the nation’s highway system following World War II. That would enable exporting resources outside SPP without the cost being paid directly by the RTO’s members or ratepayers, he said.

“We’re facing a problem because no one wants to pay for that transmission,” Wise said. “Renewable energy is really a national resource. Can this area be declared a national resource? Can we get … through Congress a transmission corridor to get to this resource? Is it necessary to have this sort of major dynamic funded and paid for by the federal government?”

Wise likened his proposal for “national renewable resource areas” to Texas’ Competitive Renewable Energy Zones, which facilitated the construction of $6.8 billion worth of infrastructure connecting West Texas wind farms with urban population centers to their east.

Oklahoma Gas & Electric’s Greg McAuley pointed out wind-energy transmission customers were the ones who invested in the CREZ lines.

“In our case, our customers can’t make use of the additional wind, at least not enough to justify significant additional investment,” he said. “It’s not clear to us how our customers would benefit from additional investment when they’re not going to be the ones using the power.”

The task force was chartered last August to establish equitable and “not unduly discriminatory prices” for exports and imports of the abundant variable energy resources in the SPP region. The RTO says it has 22 GW of renewable resources in its interconnection queue.

Since the year began, the group has discussed how other regions handle export issues and heard from representatives from Southern Co., Enel Green Power NA and Clean Line Energy Partners.

Seams Committee Approves Joint Project with AECI

The Seams Steering Committee on Friday approved a potential joint project with Associated Electric Cooperative Inc., sending it to the Markets and Operations Policy Committee and Board of Directors for final approval. Those groups will hold their regular quarterly meetings in April.

The project would include a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield, Mo.

The Morgan transformer was included in SPP’s 2017 Integrated Transmission Planning 10-Year assessment, which was approved by the MOPC and board in January. The project, valued at $9.2 million, is contingent on reaching a cost-allocation agreement with AECI.

The approval came in a special conference call, after members asked for more time during its during its March 8 meeting to evaluate the project. The vote received one abstention, from ITC Holdings. (See “AECI Joint Projects Move Forward,” SPP Briefs.)

— Tom Kleckner