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.
Dynegy will pay $750 million to buy out Energy Capital Partners’ 35% stake in their joint venture to purchase 17 fossil fuel plants in the U.S. owned by French utility ENGIE.
The companies announced the $3.3 billion venture, Atlas Power, in February. At the time, Dynegy said it was going to buy out Energy Capital’s stake in five years. (See Dynegy, Energy Capital to Buy 8.7 GW in $3.3B Deal.)
But Dynegy CEO Robert Flexon said Wednesday that the company decided to accelerate the purchase to take advantage of lower debt prices and more quickly integrate the generation assets into its fleet.
“The significant improvement in the financial markets since announcing the transaction in February provided an excellent opportunity for us to approach ECP about an earlier timetable,” Flexon said in a statement. “This transaction accelerates our company’s transformation, enabling us to increase our presence further in the most desirable markets with high quality assets.”
By buying out Energy Capital’s share early, Dynegy is paying $184 million less than the terms stated at the outset of the agreement. It will also save $40 million a year in interest.
When completed, the deal will give Dynegy an additional 9 GW of generation, slightly more than the initial 8.7 GW announced after updating for winter capacity. Ninety percent of the plants are natural gas-fired, in line with Dynegy’s quest to shift away from coal-fired generation. Flexon had said the company wanted to take on the ENGIE fleet on its own, but because it was committed to other acquisitions at the time, including $6.5 billion in two acquisitions of 19 plants from Duke Energy and Energy Capital, it needed to take on a partner.
Dynegy said it expects to close the ENGIE deal by the end of the year, after which the company will have a total of about 34.7 GW of generation, 71% of that gas-fired and 29% coal.
Exelon told New York regulators on Tuesday that it will close its Nine Mile Point Unit 1 nuclear plant next spring if the state has not guaranteed it a financial lifeline by September (16-E-0270).
The company announced its plans in a filing with the New York Public Service Commission in response to requests from commercial and industrial customers for more time to comment on an Exelon proposal for cost-based compensation for its nuclear plants. That proceeding is running concurrent with one on New York’s proposed Clean Energy Standard that includes a mechanism to compensate nuclear plants through zero emissions credits. (See New York Would Require Nuclear Power Mandate, Subsidy.)
Nine Mile Point Source: Constellation Energy Group
Exelon supported the request to extend the comment deadline until July 15, after a June 24 PSC technical conference at which the company’s proposal will be considered. Exelon also wants a pricing formula determined by the PSC by Aug. 1.
The company has previously said that it would need financial support to keep its single-unit, 581-MW R.E. Ginna plant operating after a reliability support services agreement with Avangrid’s Rochester Gas & Electric expires next March.
In a filing in May, in which it proposed the compensation plan, Exelon also said it must “make immediate decisions” regarding the nuclear plants’ continued operation. But the Tuesday filing is the first time the company said it would not refuel Nine Mile Point in March.
Exelon told the PSC its Constellation Energy Nuclear Group could not count on a CES that is “merely speculative.”
“In order for CENG to make the investment and commitment necessary to keep Nine Mile Unit 1 and Ginna in operation, it needs the certainty provided by a commission order approving the CES and a signed contract procuring zero emission credits from the nuclear generators,” Exelon wrote. “CENG cannot simply roll the dice and make substantial investments on the hope that the program ultimately adopted by the commission is sufficient to justify the substantial investments and commitments required to enable continued operation of CENG’s upstate nuclear plants. Thus, CENG will need a contract in hand by September 2016. Time is of the essence.”
Exelon said refueling the unit would cost approximately $55 million, and while the process normally takes nine months to a year, it believes it can be compressed into six months.
The company just finished refueling Unit 2 at the plant. The two units, located on the shores of Lake Ontario, north of Syracuse, generate a combined 1,900 MW.
Nine Mile Point, Ginna and Entergy’s James A. FitzPatrick plant represent the entire upstate nuclear fleet that Gov. Andrew Cuomo wants to save to help the state meet its low-carbon emissions goals. Cuomo wants to exclude Entergy’s Indian Point plant, which he wants closed because of its proximity to New York City.
Under the CES, the zero emissions credits would provide extra compensation, similar to the way in which renewable energy projects receive additional payments for their clean energy attributes.
SPP’s “year of focus” on the eight-year-old Z2 crediting project may now stretch into 2017 after the Board of Directors on Monday sided with stakeholders and delayed a vote on waiver requests that would allow the work to stay on schedule.
SPP staff last week asked the Markets and Operations Policy Committee, the Regional State Committee and the Cost Allocation Working Group to reject requests by six transmission customers for waivers that would reduce their bills under the project. All three committees tabled or took no action on the requests, despite staff warnings that the failure to act could push the project into next year.
On Monday, the board followed suit, deferring action during a special one-hour conference call with the Members Committee. The MOPC will try to resolve stakeholder concerns over staff’s reading of the RTO’s Tariff, waiver eligibility and invoice amounts during its July 12-13 quarterly meeting.
‘Full and Proper Vetting’ Needed
“I fully understand SPP’s desire to move forward and get the baseline established to do that,” said Les Evans, COO for Kansas Electric Power Cooperative, whose company is facing a $6 million bill. “We believe we need to have a face-to-face so everyone can have a full and proper vetting of the issues.”
“I listened to the MOPC call … a number of points were raised that I wholeheartedly agree with,” SPP Director Phyllis Bernard said. “I think [the vote] was premature. I think [the discussion] needs to be face-to-face. My concern is if the board [was] to take a vote today, we [would be] affirming something that isn’t particularly clear and that’s hotly disputed.”
Attachment Z2 of the Tariff details how entities that fund network upgrades can receive reimbursements through transmission service requests that could not have been honored “but for” the upgrade. But a series of problems have prevented SPP from doing a proper accounting to determine which companies owe money and which are due to receive it.
In January, the Z2 project team set a Nov. 4 date for the project’s completion. CEO Nick Brown told members that same month the project would be his organization’s focus this year. (See “Brown: Finishing Z2 Crediting Project RTO’s Top Priority,” SPP Board of Directors/Members Committee Briefs.)
$99 Million in Waiver Requests
Staff asked the three committees last week to recommend approving a different set of waivers allowing four point-to-point transmission customers to reduce their Z2 obligations. All three committees endorsed the recommendation — as did the board Monday — meaning that $56.4 million in payments due from American Electric Power, Arkansas Electric Cooperative Corp., the Northeast Texas Electric Cooperative and the Oklahoma Municipal Power Authority (OMPA) will now be allocated to the base plan and included in regional and zonal charges under SPP’s Tariff rather than being directly assigned to the companies, who were designated as “Group A.”
Staff also asked stakeholders to reject an additional $42.8 million in “Group B” waiver requests from AEP, OMPA and four additional transmission customers that SPP said don’t qualify for waivers. But Steve Purdy, SPP’s manager of generation interconnections, told the RSC an error had incorrectly included OMPA’s waiver request in Group B and said that further requests in the group may also be “waivable.”
Because the MOPC had tabled the Group B recommendation earlier in the week, the RSC voted unanimously to delay its decision until it meets July 18. The CAWG also agreed not to vote on the Group B recommendation and will discuss those waivers at its next meeting July 6.
Why Go Ahead with a Vote?
Murphy
“If we know there are issues out there, why are we going ahead with a vote?” asked Oklahoma Corporation Commission Vice Chairman Dana Murphy on June 10. “This process has been going on for eight years, and the first presentation made to us was a few months ago. If we’ve waited eight years, I don’t think a few months will cost us.”
SPP COO Carl Monroe said approving both staff recommendations would allow the RTO to continue the historical calculation of transmission credits owed and due. He said two months of work has already gone into determining who owes what and how much, work that might have to be redone if further waivers are granted.
Staff said Monday it still plans to publish the final numbers, the source of much stakeholder consternation, in September. The first invoices will be due in November.
“Part of the calculations depend on knowing the … base-plan funding rates going forward,” Monroe said. “With no action taken on this, the best we can assume is Group A is the only one waived. If that changes in the next few months, that backs us up.”
“I don’t know that July 18 affects us that much, given the eight years it’s taken to get here,” Murphy said.
Nelson
Donna Nelson, chair of the Public Utility Commission of Texas, joined Murphy in resisting the Group B recommendation. She said the situation facing the RSC was “systemic” of the larger problem facing the committee.
“Eleven years is a long time,” said Nelson, counting from 2005, when SPP created the aggregate transmission service study process that resulted in Attachment Z. “We need to have the option of doing what we think is right and not be blamed for delaying something that’s been delayed forever.”
Not Assigning Blame
Monroe said staff is not attempting to assign blame. “The intent is to continue the process,” he said.
During an open meeting of the Texas PUC on Thursday, Nelson updated her fellow commissioners on the Z2 billings. Commissioner Brandy Marty Marquez said she found the amount of money involved “shocking.”
“I can understand the concerns being raised,” Marquez said. “We are going to be concerned about the impact to ratepayers.”
Monroe
SPP staff divided the waiver applicants into two groups after spending several months calculating credit payments due from long-term reservations for transmission service and determining whether the credits should be base-plan funded or directly assigned to individual transmission customers. Staff sent reports on April 28 to all customers with directly assigned upgrade costs, giving them an opportunity to ask for waivers.
The board in April approved a level payment plan in which each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months. Payments were to begin in November, with the final installment due in August 2017. (See “Board Approves Z2 Level Payment Plan,” SPP Board of Directors Briefs.)
SPP has scheduled a two-day review session for the Z2 credit-settlement system June 28-29 at its Little Rock headquarters. The session will run 9 a.m. to 4:30 p.m. each day.
Dynegy will pay $750 million to buy out Energy Capital Partners’ 35% stake in their joint venture to purchase 17 fossil fuel plants in the U.S. owned by French utility ENGIE.
