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.
MISO is unlikely to meet a July 15 target for filing its proposed competitive retail solution (CRS) with FERC, raising doubts that changes can be implemented in time for the 2017/18 planning year.
Jeff Bladen, MISO executive director of market services, said the timeline has been placed on hold while the RTO and its Independent Market Monitor attempt to strike a compromise.
Bladen announced the delay during a Monday conference call of the Resource Adequacy Subcommittee (RASC), where the RTO had intended to review draft Tariff language. “Given the ongoing work with the Market Monitor on alternative approaches … we did not post draft Tariff language,” Bladen said.
He said MISO will continue to work with the Monitor until a “hybrid” version of the competitive retail solution emerges. MISO’s Board of Directors ordered staff and Potomac Economics into negotiations late last month. (See Board Orders Negotiation in Auction Disagreement.)
Pressed by stakeholders, Bladen said a July filing is becoming “less likely.”
Audrey Penner, market access and regulatory affairs officer at Manitoba Hydro, asked when MISO would have to file in order to implement changes in time for next year’s capacity auction.
MISO RASC liaison Renuka Chatterjee said a filing targeting 2017/18 implementation could be submitted as late as September. But she added, “We feel the further we get away from July, the less likely a 2017/18 implementation is.”
Dynegy’s Mark Volpe said “a 2017/18 implementation is paramount to Dynegy” and asked that August be used to vet the hybrid resolution.
MISO’s auction design timeline, released earlier this month, will be reworked to include later draft Tariff language release and filing dates. The March launch of the competitive retail solution is also in question.
Seeking Common Ground
While both MISO and the Monitor want unique auction treatment and use of a sloped demand curve for competitive retail areas such as Southern and Central Illinois, the two differ on other key elements:
The Monitor maintains the entire footprint can be kept on a prompt auction schedule and says MISO’s proposed three-year forward auction will create doubt in generators wanting to suspend or retire.
The Monitor wants all planning needs represented with a sloped demand curve; MISO wants to use the sloped curve only in competitive retail areas.
“What we’ve been talking about is a prompt hybrid and a forward hybrid, and at some point we’re going to have to choose which one to present to FERC,” Potomac’s Michael Chiasson said.
“While I can speak to what has been proposed, I can’t talk about what a final proposal would look like,” Bladen said. “We simply don’t have one today.”
Whatever hybrid resolution results, Bladen said there is “no chance” MISO will support a forward auction for the entire footprint.
Bladen said he hoped to have an outline of a hybrid proposal by the RASC’s next meeting, June 29-30.
Ameren, Dynegy, Industrials Weigh In
Both Ameren Illinois and Dynegy say they prefer the Monitor’s proposal over MISO’s. In comments submitted to the RTO last week, Ameren repeated its call for a single Planning Resource Auction with the addition of a sloped demand curve for deregulated areas.
“Our position at this time continues to be opposition to the MISO proposal in favor of the concepts put forth by the IMM. … Our support of the IMM proposal is conditioned on reviewing more detailed information in the future, including any proposed tariff language and/or changing dynamics in Illinois,” the company said.
Dynegy says MISO’s proposal does not address minimum offer price rules or other means for mitigating buyer market power. “Dynegy would prefer MISO embrace the co-optimized prompt year-only CRS market design proposed by the IMM because we believe Dr. [David] Patton’s proposal lays out a viable foundation for efficient price formation,” the company said.
Illinois Industrial Energy Consumers repeated its earlier stance that the entire proposal is unwarranted: “IIEC continues to believe the MISO [proposal] is unnecessary for either Southern Illinois or the broader MISO footprint and would act to unduly subsidize generation resources at the expense of consumers even when the capacity market is not tight.”
Bladen called the feedback “helpful” but declined to address any specific points raised by the three entities. “Having that kind of well-thought-out commentary is very valuable as MISO has these alternatives on the table,” he said.
Avoidable Costs Filing Remains on Track
MISO’s announcement of the delay comes little more than a week after it again pushed back its schedule for proposed seasonal and locational auction constructs. Meanwhile, RTO officials said the FERC-required filing on avoidable costs is expected to take place as planned on June 28.
Staff members are recommending that the Maine Public Utilities Commission not approve natural gas pipeline capacity contracts paid for by electric and gas customers.
Opponents of the Northeast Energy Direct pipeline marching in protest. (Source: PopularResistance.org)
An Examiners’ Report released last week said market changes since the price spikes of 2014’s polar vortex make it unlikely electric generators will make commitments for pipeline capacity in an effort to stabilize prices.
“The commission does not find that the market and rule changes to date are likely to alter the fact that the region’s generators do not make long-term commitments for pipeline capacity,” the report said, which is written as a draft order (2014-00071).
Maine’s Energy Cost Reduction Act, passed in 2013, authorized the PUC to execute “energy cost reduction contracts” for 200 million cubic feet of natural gas costing up to $75 million a year, if it found that the contracts would save ratepayers money. The law allows the PUC to administer and resell the pipeline capacity.
The report said that much has changed since the law was passed and that historic low prices for natural gas have removed the urgency felt two years ago.
The report comes two weeks after Kinder Morgan withdrew its application with FERC for the Northeast Energy Direct pipeline through New England, citing a lack of commitments from potential customers and an uncertain regulatory outcome for ratepayer financing.
“Hot on the heels of the recent downfall of Kinder Morgan’s massive pet pipeline project, this is an important victory on the path to stopping the patchwork effort across New England to build a polluting pipeline on the backs of consumers,” pipeline opponent Conservation Law Foundation said in a statement.
“We believe there is a strong case that electricity prices will be lower if the region has more gas pipeline capacity,” Tim Schneider, the state’s public advocate, told the Portland Press Herald. “This is why we supported Maine buying capacity as part of a regional effort. If Maine doesn’t buy capacity, it puts the regional effort at risk.”
Wholesale power costs in CAISO fell sharply last year as lower natural gas prices, increased solar generation and reduced loads more than offset the impact of a steep decline in hydroelectric output, according to a report from the ISO’s Department of Market Monitoring.
Solar output last year surpassed all other forms of renewable generation for the first time since CAISO began operation.
The ISO’s total cost of serving load decreased 31% to $8.3 billion in 2015, compared with $12.1 billion the previous year, the department said. Average wholesale costs dropped to $37/MWh from $52/MWh in 2014.
“Declining gas prices clearly had a role in the decrease,” Keith Collins, CAISO manager of monitoring and reporting, said during a June 7 call to discuss the report.
Collins noted that the 40% decline in California gas costs followed a national trend, with SoCal Citygate and PG&E Citygate prices falling along with the benchmark Henry Hub price. He also pointed out that, controlling for gas prices, CAISO power costs were down only 6% year-over-year, a decrease likely attributable to a sharp rise in output from low-cost solar. Lower congestion and increased virtual supply — which improved convergence between day-ahead and real-time prices — added downward pressure, the department said.
Last year also saw a seemingly contradictory movement between total loads and peak loads, with the former down and the latter up. Collins noted that a September heat wave produced CAISO’s highest annual peak load in five years, up nearly 5% from the 2014 peak.
Total and average load fell slightly for the year, continuing a trend of modest declines since 2012. The department attributed the drop-off to the growth of rooftop solar capacity, which the ISO estimates may have reached 4,000 MW last year.
Grid-connected solar reached a milestone in 2015, surpassing wind to become the largest source of renewable generation in the CAISO system. Solar output increased 38% during the year and accounted for nearly 7% of system energy. Wind output fell slightly, accounting for 5% of total supply. In 2014, solar provided less than 5% of system energy, below wind’s 5.6%.
Geothermal generation also accounted for about 5% of supply, gaining 24% over the previous year. The department attributed the increase to a group of geothermal units formerly outside CAISO’s footprint coming under its control.
In total, non-hydro renewables accounted for 18% of supply — not counting renewable imports — compared with 40% from natural gas and 8% from nuclear. Hydro (5%) and imports (28%) made up the balance.
While NV Energy did not join the CAISO-run Western Energy Imbalance Market (EIM) until the final month of 2015, Collins reiterated the ISO’s observation that the utility’s membership quickly unified what was previously a fractured market. (See NV Energy Has Smooth EIM Integration, CAISO Says.)
“The inclusion of Nevada really changed the dynamic of the market,” Collins said. The increased transfer capacity from NV Energy’s transmission network has significantly improved the link between CAISO and the PacifiCorp East (PACE) balancing area, creating more uniform pricing for imbalance energy, he said.
“We see the optimization creating a one-EIM price for those regions,” Collins said.
Other highlights of the report:
Hydroelectric output dropped for the fourth straight year in the face of extreme drought, falling to one-third the 2011 level. Snowpack in the Sierra Nevada mountains — a natural store for run-of-river hydro operations — was at 3% of normal on May 1, 2015.
Net imports fell 2% from 2014, mostly because of decreased imports from the Southwest. The department said the drop-off likely stemmed from lower price differentials between Southern California and the Palo Verde trading hub in Arizona.
Intervals of negative pricing in Southern California during the second quarter were attributed to combined surpluses of wind and solar generation during a period when outages on the Path 15 transmission line limited flows to the northern part of the state. Negative prices in the 15-minute market occurred in about 4.7% of intervals during that quarter, compared with an average of 2% for the year.
New York could accommodate up to 4,500 MW of wind generation and 9,000 MW of solar photovoltaic capacity by 2030 with no system reliability issues, according to a NYISO draft study released last week.
The backdrop to the “Solar Integration Study” is New York’s Reforming the Energy Vision initiative, which promotes adoption of cleaner and more distributed energy resources as well as state incentives that promote rooftop solar generation. New York’s Clean Energy Standard also mandates the state derive 50% of its electricity from renewables by 2030. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.) The NYISO study focuses on system impacts — rather than the costs or economics — of renewable energy.
A National Renewable Energy Laboratory study this year found that New York has the potential to install 46.4 GW of rooftop solar PV — which represents the upper limit of potential installations rather than a prediction, the study notes.
“The growth of solar PV energy as a source of electric generation is being strongly influenced by various public policy initiatives, including programs established by the State of New York in the State Energy Plan,” NYISO said.
The NYISO study included:
Development of hourly solar profiles and a 15-year solar PV projection by zone in New York;
“Lessons learned” and integration studies from other regions experiencing significant growth in solar and wind resources;
The impact of various levels of solar PV and wind penetration on the state’s grid regulation requirements; and
Potential reliability concerns associated with the frequency and voltage ride-through characteristics of solar installations.
The study points out that the $1 billion NY-Sun Initiative announced in 2012 will yield 3,000 MW of solar PV for the state, more than 500 MW of which had been installed by the end of 2015.
“As the penetration levels of solar PV and wind increase, any projected increases in regulation requirements are relatively minor and can readily be accommodated within the current market rules and system operations,” the study says.
The study recommends that NYISO advocate for industry standards requiring solar inverters to have voltage and frequency ride-through capabilities and request that the state establish similar requirements for the non-bulk power system.
NYISO says the study will lay the groundwork for additional research by the ISO.
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.
