FERC last week granted PacifiCorp’s request to suspend the relicensing proceeding for the 169-MW Klamath Hydroelectric Project in order to give the utility more time to transfer the facility to new owners ahead of the removal of four dams (Project No. 2082-027).
The fate of the project — which straddles the California-Oregon border along the Klamath River — became the subject of negotiations among state and federal agencies, Native American tribes, environmental groups and local farmers in 2008. Two years later, PacifiCorp reached a settlement agreement to remove four of the project’s dams, contingent on passage of federal legislation authorizing the removal.
Congressional inaction triggered dispute resolution proceedings early this year, resulting in PacifiCorp agreeing to transfer the project’s license to a new entity — the Klamath River Renewal Corp. — in July. That entity is expected to immediately file with FERC to surrender and remove the dams under the commission’s process, rather than await approval from Congress.
“Requiring the parties, other stakeholders and commission staff to simultaneously proceed with both a relicensing proceeding and a transfer and surrender proceeding would be burdensome and an inefficient use of resources,” the commission said in its ruling.
The Irongate Dam is one of four scheduled to be removed from the Klamath River. Source: American Rivers
FERC last week accepted a NextEra Energy compliance filing revising a tariff for two transmission projects the company has been awarded through CAISO’s competitive selection process (ER15-2239-002).
The commission agreed with NextEra’s explanation that the tariff’s formula rate would only apply a 150-basis-point adder to an initial assessment of the long-term cost of debt for the projects — a figure based on the company’s debt cost for a Texas project. The adder, the company clarified, would be recalculated once long-term debt is actually issued.
The commission also rejected a request by the California State Water Project that NextEra’s tariff clarify the term “third-party debt,” ruling that the argument was outside the scope of the proceeding.
“The commission has repeatedly held that compliance filings are limited to the specific directives of the commission’s order,” the commission wrote. “The sole issue on review is whether the filing party has complied with those directives.”
NEW YORK — Organized markets are being distorted because of policymakers’ failure to price carbon, two grid operator CEOs and a former FERC and state commissioner told a New York Energy Week audience last week.
“I would say that in my … 16 years, this is the most vulnerable that I’ve seen the market construct yet,” ISO-NE CEO Gordon van Welie told more than 75 industry participants at Goldman Sachs’ office in lower Manhattan.
Van Welie appeared on a panel with NYISO CEO Brad Jones and former FERC and Pennsylvania Public Utility Commissioner Nora Brownell, who both joined van Welie in lamenting that CO2 emissions remain a market externality. The conference was created in 2013 by EnerKnol, an energy policy research and data company.
Left to right: Moderator Rich Heidorn Jr., RTO Insider; Gordon van Welie, ISO-NE; Brad Jones, NYISO; former FERC Commissioner Nora Mead Brownell Copyright: New York Energy Week
“We value what nuclear brings to the table” as a baseload, low-carbon resource, Jones said. “But our markets don’t.”
Asked about Gov. Andrew Cuomo’s proposed zero emission credits for upstate New York nuclear units, Jones said, “We’d like to see that be temporary in nature … a bridge into a future where the market can really resolve these issues.”
Obvious Solution
Brownell was blunt.
“We don’t have the leadership to deal with the obvious solution, which is a carbon tax. It’s straightforward, it’s transparent, it sends the right market signals,” said Brownell, who served on FERC from 2001 to 2006. “The market signals are there; we’re not allowing them to really work. And the more we create these constructs, the more we ultimately distort markets.”
Van Welie said the lack of carbon pricing is putting the public policy of achieving reliability through wholesale markets in conflict with that for reducing carbon emissions.
Allowing resources with “out-of-market” contracts under state clean energy procurements to offer into the capacity market will distort price formation, said van Welie. “And that really creates a problem in terms of ensuring reliability, but it also creates a problem with regard to the long-term incentive in the market as well.”
‘Fundamental Questions’
Brownell said the conflict raises “fundamental questions.”
“Do we really value markets, and have we done a sufficient job of illustrating the economic benefits of markets?
“Secondly, what is the role of the RTO? We have piled on … to what was originally a pretty straightforward economic dispatch reliability model. I’m not saying they are incapable of doing this; I just wonder if they are the best entity to do it. Or we are burdening them to the point where they really can’t do their fundamental job well, which is ultimately and critically important to both economic development and the environment in which we live.”
Building Infrastructure
Brad Jones, NYISO Copyright: New York Energy Week
Jones and van Welie also shared their challenges in building the electric and gas infrastructure needed to meet reliability and environmental goals.
Jones noted that it has historically taken 10 to 12 years to get new transmission approved, sited and constructed in New York.
Based on that, he said, the ISO “would have two years remaining in our 14 years to interconnect everything into the system to meet the [2030 state goal of 50% renewables]. That is not possible. We have to improve our ability to move these projects through the system.
“Given that we have a single siting authority, it does give us the advantage to begin to streamline that process,” he added.
For the six-state ISO-NE, siting issues are compounded by cost allocation disagreements.
Unlike the “singular objective” that made the region’s $12 billion transmission buildout for reliability possible, there is less consensus on transmission to deliver renewables, said van Welie.
Part of the problem is that some renewable developers are trying to connect in weak parts of the region’s grid. “Up in Maine, we have 3,000 MW of wind projects trying to interconnect to a transmission system designed to serve 300 MW of load,” van Welie said.
“We’ve spoken to the developers and said, ‘Why don’t we do a cluster study and why don’t you guys sort of get together and pool your money and all share in this investment that’s required and we can get you all connected?’ They don’t want to do that.
“And then we turn around to the states and say, ‘There’s a bunch of wind developers up here in Maine, some of which have actually signed contracts with you,’ he continued. “‘Can’t we get you guys to pay for some transmission to integrate them?’ And we can’t get that to happen either. And so we’re stuck, quite honestly.”
Van Welie said he has some hope that state clean energy solicitations will break the log jam.
“Maybe they’ll choose one that’s up in Maine and we’ll actually resolve this problem,” he said. “If they don’t, I think we’re going to remain stuck.”
Cost Allocation
Complicating New England’s transmission challenge is the Order 1000 cost allocation methodology approved by FERC. “The northern states don’t agree with the cost allocation and they’re the ones that would have to site these transmission projects,” van Welie said. “Ultimately I think we’re going to do something like what Texas did” with its Competitive Renewable Energy Zones (CREZ), he said.
Jones, who worked for ERCOT and Luminant before joining NYISO last year, said he sees lessons in how Texas and California — other single-state ISOs — were able to build renewables.
“In order to meet this aggressive goal, we have to begin identifying in advance where we think some of these renewables will locate. And then by that identification we can begin to build out a collector system, which allows those renewables to feed into the market,” he said. “We have to begin to remove some of that risk that is … on the developers by building out transmission to locations where we think there’s a high probability for those developers to come.”
Gas-Electric
For New England, the challenge of upgrading the transmission grid is compounded by its stressed natural gas infrastructure. This is a concern, van Welie said, because gas will be needed to balance renewables for the next “several decades,” until storage becomes more affordable.
“One of the most vexing problems we have is this disconnect between how the gas industry is regulated and the electric industry is regulated,” he said. “I think we all launched into wholesale markets 15 years ago thinking that the markets would do a great job of optimizing existing infrastructure, and of course they’ve done that. But we have now pushed the gas system to the limit.”
“So there’s nobody looking out to say, ‘How do we plan the gas system to be able to make efficient fuel delivery to the electric system?’ When we’ve approached the FERC on this issue, basically they’re boxed in because of the Federal Power Act.”
Brownell echoed van Welie’s concern, urging “integrated planning.”
“We need to look at the entire infrastructure needed. Texas [CREZ] worked. It just totally worked. … We just cannot continue to do things state by state, silo by silo, policy by policy,” she said.
Distributed Generation, New York REV
The panelists also gave their views on distributed generation, New York’s Reforming the Energy Vision initiative and its proposed rewrite of the utility revenue model.
“The debate about the big or the small grid [being] either/or is not really a debate that I buy into,” Jones said. “It really has to be both. We can’t … have a large renewable program and then trust that all that will be developed in rooftops. … To get the efficiencies out of building renewables in a way that just doesn’t cost too much for all of our customers, we need to do that in large scale. And so a lot of that large-scale [generation] will be a distance away from our [load] so it really has to be a combination of both the big grid and the small grid.”
Former FERC & PA PUC Commissioner Nora Brownell Copyright: New York Energy Week
Brownell, who served on the Pennsylvania commission (1997-2001) when it eliminated utilities’ monopolies and adopted customer choice, and now serves on the board of National Grid, was asked her reaction to the New York Public Service Commission’s May order seeking to change the utility revenue model.
Instead of earning returns on investments in large, centralized power systems, utilities would have “earnings opportunities” based on their performance as a “platform” enabling distributed resources and other new technologies. (See NY REV Order Revamps Utility Business Model.)
“Utilities cannot deny that the business model is changing with them or without them,” she said. “So I think there is real leadership among some — not all — to be part of that solution.
“The challenge is that if you’re going to have performance metrics — and we’ve seen them in the U.K.; they’ve worked for years — they need to be clear, they need to be measurable. You can’t have what you had in the telecom industry, which was: ‘We’ll give you extra money for doing the following 10 things, but we’re not going to really measure whether you’ve done them.’”
Mike Kormos, who abruptly resigned in March from his post as PJM executive vice president and chief operations officer, began a job last week as Exelon’s president of wholesale markets and energy policy.
Kormos copyright RTO Insider
“Mike brings extensive knowledge of the wholesale electricity markets,” said Joe Dominguez, executive vice president of governmental and regulatory affairs and public policy. “His expertise in market innovation and design … will strengthen Exelon’s policy efforts as we continue to advocate for market reforms that will benefit our customers, our communities and our companies.” (See Exelon to Close Quad Cities, Clinton Nuclear Plants.)
Kormos was with PJM for 27 years, and last year he sought to replace retiring CEO Terry Boston. The post went to Andy Ott, who long had been Kormos’ equal on the organizational chart. (See Kormos Marks Quarter Century Mark at PJM.)
At the time of Kormos’ resignation, Ott said his position would not be filled. Ott this month announced organizational changes, assigning Kormos’ duties overseeing the Operations Division to Senior Vice President Stu Bresler. (See Ott Restructures PJM Divisions, Leadership.)
In his new role, Kormos will be in charge of formulating and furthering Exelon’s positions on energy and transmission bulk system policy planning, developing effective wholesale energy markets, overseeing the company’s participation in NERC initiatives and monitoring grid reliability issues, including cybersecurity, the company said.
Kormos, who will report to Dominguez, has served on several boards, including the Eastern Interconnection Planning Collaborative, Reliability First Corp. and Eastern Interconnect Data Sharing Network.
He holds a bachelor’s degree in electrical engineering from Drexel University and earned an MBA from Villanova University.
FERC last week clarified its December ruling ordering settlement procedures for new SPP member Central Power Electric Cooperative’s transmission service rates while denying a request for rehearing (ER16-209).
The commission’s December order accepted revisions to SPP’s Tariff that added a formula rate template and implementation protocols to recover revenue from the use of Central Power’s transmission facilities. FERC also established hearing and settlement procedures. The North Dakota utility became an SPP member on Jan. 1.
Otter Tail Power, a MISO member, filed a request for clarification and rehearing, which was supported by regulators in Minnesota, North Dakota and South Dakota.
The utility asked FERC to ensure all issues related to the Integrated System were included in the settlement proceeding. Otter Tail also asked for a rehearing of the commission’s decision not to address rate pancaking or to impose a hold-harmless condition as a result of Central Power joining SPP.
FERC agreed with Otter Tail’s and the state regulators’ separate requests for clarification, saying it intended to include in the settlement hearings “whether any service agreement provisions are needed to mitigate the impact of duplicative or pancaked rates on the integrated transmission system.”
However, the commission rejected the rehearing request over pancaked rates, asserting “separate inter-RTO transmission charges are consistent with commission precedent.” FERC said Otter Tail could address its concerns over credits for transmission facilities and having to pay for year-round SPP transmission service in the settlement procedures.
FERC also rejected Otter Tail’s argument that it had “erred” in dismissing a request for a hold-harmless condition, citing precedent in other cases.
MISO has named Kari Bennett as its new executive director of external affairs — the third person to take on the position in less than five years.
Kari Bennett, MISO
Bennett joined MISO in December 2013 as senior corporate counsel and most recently served as the RTO’s senior director of program strategy. She previously served as a commissioner on the Indiana Utility Regulatory Commission.
Indiana’s inspector general cleared Bennett’s move to MISO after determining it would not violate the state’s revolving door policy because she would not lobby the commission in her new role.
Bennett replaces Michelle Bloodworth, who served in the post for just over a year. Bloodworth started a firm, MAB Consulting, in Birmingham, Ala.
John Shepelwich served as MISO’s director of external affairs from October 2011 to June 2013 before returning to AEP Virginia to assume the role of communications manager.
FERC last week gave the go-ahead for Entergy Arkansas to collect the wholesale portion of its service company’s annual decommissioning requirement for Arkansas Nuclear One’s Unit 2 (ER16-644).
The commission’s June 16 order addressed a December request by Entergy Services to allow Entergy’s Arkansas operating company to recover the annual decommissioning requirement in its rates.
Entergy told FERC the Arkansas Public Service Commission recently slapped a $2.87 million annual decommissioning requirement on Unit 2. It asked the commission to allow Entergy Arkansas to collect the $155,554 owed under its Tariff by Entergy’s Louisiana and New Orleans subsidiaries.
Arkansas Nuclear One Source: Entergy
The New Orleans City Council protested Entergy’s initial filing, opposing the company’s waiver request of the notice requirements for future changes to the annual decommissioning requirement. Entergy responded by clarifying it would give the council the opportunity to review and participate when making future changes.
FERC ordered Entergy to make a compliance filing within 30 days and said any increases in the annual revenue requirement would require a new filing and updated studies.
Nuclear One’s 987-MW Unit 2 went online in 1980, and its current licenses expires in 2038. It is one of two nuclear units at the site along the Arkansas River in western Arkansas.
FERC ordered MISO last week to revise its Tariff to ensure it is not overpaying for reactive power or show cause why it should not have to do so (EL16-61).
Currently, MISO can compensate resource owners for providing reactive supply and voltage control service, even after the units are deactivated or transferred to another owner.
During a Thursday Organization of MISO States board meeting, Chris Miller, of FERC’s Office of Energy Market Regulation, said the RTO would have a difficult time convincing the commission it should not make the change.
In 2014, the commission issued a similar order requiring PJM to stop making reactive power payments to retired generation.
FERC also directed MISO to “post to its website and maintain a chart that lists all resource owners whom receive compensation for reactive service along with their respective current reactive service revenue requirements.”
Avon Lake Wikimedia
NRG Midwest to Repay PJM
In a related order, the commission ordered NRG Midwest to repay PJM with interest revenue the company received for reactive services at the Avon Lake coal plant over about three months after it deactivated one unit (ER16-1443).
Avon Lake’s Unit 7, located west of Cleveland on Lake Erie, was deactivated in mid-April but continued to collect reimbursement for reactive services while NRG Midwest’s April 18 revised rate schedule was pending. The closure of the unit reduced Avon Lake’s annual revenue requirement for reactive services by almost $163,000 to $1.6 million.
In the order, FERC accepted NRG’s adjusted revenue requirement for reactive services, which reflects the diminished generation at Avon Lake. FERC also created a new docket (EL16-72) to determine whether NRG’s reactive power rate for its fleet in the American Transmission Systems Inc. zone of PJM is reasonable.
In May, the commission approved revised reactive services rates for Constellation Power Source Generation in accordance with the 2014 order. (See “Constellation’s Reactive Payments Cut Due to Retirements,” FERC Rulings in Brief: Week of May 19.)
The Organization of MISO States is reviewing and revising its decision document — the rules for approving position statements submitted to MISO and FERC.
Last updated in 2009, the document describes the group’s guidelines for creating issue statements, discussing and voting on issues, and filing comments.
An ad-hoc working group has been modifying the document in a “half-dozen” conference calls, Public Service Commission of Wisconsin administrator Janet Wheeler told a June 16 meeting of the OMS board.
The group will hold at least one more meeting the last week of June to finalize the document, which will be presented for board approval in July.
OMS President Reacts to Survey Results
OMS President Sally Talberg spoke with the board about the recently released OMS-MISO survey results, which indicate the RTO may face a generation shortfall in 2018. (See OMS-MISO Survey: Generation Shortfall Possible by 2018.)
Talberg noted the 2018 outlook would have been “gloomier” if not for the fact that MISO load growth and demand are down for the second year in a row.
OMS Looking for New Employees
OMS is seeking to hire a director of member services and advocacy and a part-time office assistant in its Des Moines office. Resumes will be accepted until July 1.
ERCOT’s Board of Directors last week unanimously approved two transmission projects intended to ease congestion and reliability concerns in South Texas, where proposed LNG plants are expected to increase the region’s load.
The Regional Planning Group’s Valley Import Project will add a static VAR compensator at two 138-kV substations, at an estimated cost of $91 million. The Hidalgo-Starr Project will result in two new 345-kV lines, a 345-kV double-circuit line, two 345/138-kV transformers and various other improvements in the North McAllen-Edinburg region. The project is estimated to cost $51.5 million.
Both projects are projected to go into service as early as 2019.
Two LNG plants have already been approved for Corpus Christi and Brazoria, south of Houston. Another eight plants have been proposed, including six — an additional 2,400 MW of load — for the Port of Brownsville on the Mexican border.
ERCOT said further improvements may be needed to meet the Rio Grande Valley’s load in 2023, but the compensators will buy time until a long-term solution addresses the challenge.
“The issue we face is a limited amount of generation in the Valley,” Warren Lasher, ERCOT’s director of system planning, told the board June 14. “This is a situation where if we could get generation to site in the Valley region, it would significantly increase reliability in the region and preclude the need to build more transmission. … If [the two projects] get built, we would not need additional transmission into the Valley.”
Lasher said two large combined cycle gas plants have signed generation interconnection agreements, but neither were included in the planning models as they have not yet been “collateralized.” Staff did conduct a sensitivity analysis that assumed 780 MW of new generation and 700 MW of LNG load; it showed reliability criteria could be met without additional import facilities.
Board member Judy Walsh, a former Texas commissioner and MISO’s board chair, wondered aloud whether building additional generation might be a cheaper alternative.
“It looks like chicken and eggs to me,” she said. “Without a [financial] product to incent generation, it makes it less likely generators will build.”
“If the board approves this, if the SVCs are installed, would that discourage new generation?” asked Public Utility of Texas Commissioner Ken Anderson, who also suggested eliminating mitigation schemes and letting prices rise.
Lasher said congestion pricing would influence future decisions about generation, but the SVCs could also play a role by changing the voltage-stability limits in the Valley.
“The SVCs will not be competing with the generation units. They will be changing the voltage-stability limits in the Valley, and may actually support the ability for thermal-based congestion to create a little more pricing incentive.”
Anderson also asked whether eliminating mitigation schemes in the Valley and letting prices rise would lead to the construction of more generation.
“The challenge in the Valley is that it doesn’t affect just the Valley,” pointed out Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitoring Unit. “It affects all the prices in the South load zone.”
Two transmission projects went into service in the region during the last two months, easing some of the congestion issues. However, the 524-MW Frontera combined cycle plant will disconnect from ERCOT during the third quarter and begin dispatching into the Mexican market. The plant is owned by Viva Alamo, a subsidiary of The Blackstone Group. [An earlier version of this story incorrectly identified the owner as Direct Energy, which sold the plant to Viva Alamo in January 2014.]
“One thing in favor of strengthening transmission … is that it’s pro market,” said unaffiliated board member Peter Cramton. “It allows a larger set of generators to compete in a more robust marketplace. You don’t always want to throw money at transmission, but at same time, you have to recognize it’s transmission that’s enabling the market.”
American Electric Power, which owns the two substations that will be upgraded and proposed both projects last year, will handle the construction. Sharyland Utilities and CPS Energy also submitted a proposal for the Valley Import Project.
The chairman of the New York State Senate energy committee called on the Public Service Commission Wednesday to immediately implement the nuclear subsidy in the proposed Clean Energy Standard before the entire proposal is finalized.
The move came a day after Exelon said it would close its 620-MW Nine Mile Point Unit 1 nuclear facility early next year if the state doesn’t complete regulations and have a signed contract with the generator by the end of September. (See Exelon Threatens to Close Nine Mile Point 1.)
“There is one thing everyone agrees on, and that’s the pressing need to make sure that our nuclear fleet does not retire prematurely due to current economic conditions in the energy sector,” said Republican Joseph Griffo, chairman of the Senate Energy and Telecommunications Committee.
Griffo Source: NY Senate
The “Tier 3” of the CES is a special payment for nuclear generating stations that credits them for zero carbon emissions. Other tiers of the CES create incentives for wind, solar and other renewable resources.
“There are many opinions about how best to go forward with the broader Clean Energy Standard and, in particular, how to do so in the most cost-effective way for consumers,” Griffo said. “We need to slow down and evaluate the full CES more carefully in order to reach our goals while protecting ratepayers.”
“The department fully understands the difficulties facing the upstate nuclear fleet, which is why we have been working for the past six months to create a plan that will ensure the future viability of these emission-free resources and continue New York’s progress in reducing greenhouse gas emissions,” it said in a statement.
Griffo was joined in his statement by several state legislators from districts that include or are near to the upstate nuclear fleet on Lake Ontario. The other plants are Exelon’s Nine Mile Point Unit 2 and R.E. Ginna station near Rochester and Entergy’s James A. FitzPatrick plant. Entergy has said it will close FitzPatrick, and Gov. Andrew Cuomo has excluded its Indian Point facility near New York City from eligibility for the CES.
Nine Mile Point Source: Constellation Energy Group
Separately, the Oswego County Industrial Development Agency issued its own statement advocating quick action.
“Nine Mile Point 1, and the thousands of families and jobs it supports, as well as the surrounding community, and our state, needs regulators to implement the CES as soon as possible. We are very close to the finish line in this regulatory process, and the news that the plant could shut down without the CES is a reminder that the state’s economic and environmental future is now at stake,” CEO L. Michael Treadwell said.
