Page 1442 – RTO Insider

May 2, 2016

Developer Proposes Underwater HVDC Cable to New York City

By William Opalka

A merchant transmission developer asked FERC last week for authority to negotiate transmission contracts for a mostly underwater cable to transport 1,000 MW of electricity underneath 260 miles of the Erie Canal and Hudson River to New York City (ER16-1495).

Erie Canal (NY State Canal Commission) - underwater cable new york city — Erie Canal *Source: New York State Canal Commission*

Empire State Connector filed an application for transmission service on a HVDC line that would deliver renewable energy from upstate New York.

ESC is a joint venture of Toronto-based transmission developer oneGrid and investment firm Forum Equity Partners. The company says it is assuming the entire financial risk of the $1.5 billion project. It asked for FERC approval by June 26 to keep to its preferred permitting and open season schedule.

“Our strategic location and innovative, low-impact route will ‘unlock’ upstate renewable and ‎zero-emission generators, helping New York state achieve its ambitious goal of 50% renewable generation by 2030,” CEO John Douglas said in a statement.

The project would originate at a converter station located near Utica and terminate at a converter station located in either the Bronx or Brooklyn. Underground cables would be connected to a new converter station near the existing Marcy substation near Utica until it enters the canal. Cables would be buried under the locks and dams along the canal route.

The company said a NYISO feasibility study concluded the project is viable and it has secured a spot in the ISO’s interconnection queue.

ESC said it will file its Article VII application for major infrastructure review certification with the New York Public Service Commission by the end of the year. It will also conduct a solicitation later this year seeking subscribers for capacity on the line.

The project will create more than 500 construction jobs and 1,200 indirect jobs during the three-to-four-year construction period, the company said. Each converter station is estimated to cost more than $200 million. The target in-service date is for some time in 2021.

The NYPSC in December declared a public policy need for above-ground transmission to move upstate power from central New York to the New York City area through AC lines that are using existing corridors. (See NYPSC Directs NYISO to Seek Tx Bids.) Douglas told RTO Insider on Monday that he sees ESC and above-ground AC as “complementary.”

“New York state certainly has ambitious goals to develop renewable energy,” Douglas said. “It’s going to need a lot of new transmission, especially if it succeeds in closing Indian Point. So we see … room for both [projects] for both energy and capacity.”

May 2, 2016

ERCOT Tech Advisory Committee Briefs

ERCOT’s Technical Advisory Committee voted last week to dissolve its Distributed Resource Energy Ancillaries Market (DREAM) task force, agreeing the group had brought issues to the forefront that could now be taken up in the ISO’s stakeholder process.

The DREAM team was created last May to investigate the regulatory and market framework for distributed energy resource (DER) participation in ERCOT’s wholesale markets.

Shell Energy’s Greg Thurnher, the DREAM team’s chair, said the goal was to establish a marketplace where price-taking and price-responsive distributed generation (DG) resources can efficiently coexist.

Expanding the scope of price-responsive loads and resources in security-constrained economic dispatch, he said, more accurately reflects the price elasticity of demand.

“In the eyes of TAC, I think we’ve achieved our charter,” said Thurnher, who represents the Independent Power Marketer segment.

TAC Chair Randa Stephenson, with the Lower Colorado River Authority, agreed and thanked the team for its work. “We’re now at a point where we can vet specific and technical issues through the stakeholder process,” she said, before casting the only abstention in an otherwise unanimous vote.

Thurnher said Shell will sponsor a nodal protocol revision request (NPRR) following up on the DREAM team’s recommendations. He has proposed five market rule changes for price-responsive DG, among them a proposal to exclude the resources from participating in ERCOT’s congestion revenue rights markets.

He would also exclude DG from participating in regulation until distributed storage becomes larger and more cost competitive. DG “is a low-cost hedge, it’s out there and it’s growing. These assets are right-sized and can solve many of the smaller constraints we have on our system,” Thurnher said. “When you have resources with no load responding to the system, they should be given the opportunity to bid into the market and contribute to price formation.”

Kenan Ögelman, ERCOT’s vice president of commercial operations, responded with a spreadsheet listing 15 short- and long-term issues identified by the ISO as needing revision requests or new market rules. “The idea was to put down ERCOT’s perspective on what our needs are,” he said.

Ögelman said staff looked initially at accounting for larger resources and then tried to capture smaller resources. He said the focus was on “what’s in the market, instead of getting these resources participating in the market.”

“Some of these things are what Greg was talking about,” Ögelman said. “We understand your priorities might be slightly different, and we’re happy to work with you and move them up. This is not written in stone.”

Ögelman said he would like to combine Thurnher’s proposals with ERCOT’s spreadsheet and hand the effort over to a working group. He said he would be “looking for input and timing from the market as to when these should come into play.”

Several stakeholders expressed concern smaller market participants might lack the resources to ensure their voices are heard in stakeholder proceedings. Others cautioned about moving too quickly to allow stakeholders to provide input.

Stephenson said she will work with ERCOT “to ensure the right people,” including distribution utilities, are involved in the discussions.

TAC Approves Addition of Responsive Reserves

The TAC approved staff’s recommendation to add 200 MW of responsive reserve service (RRS) during the afternoon hours in July and August. The vote came after the TAC asked ERCOT to include in its 2017 ancillary service methodology review an analysis of how the elimination of the reserve discount factor (RDF) would affect operations.

The ISO’s current minimum RRS requirement is 2,300 MW under normal conditions. The additional 200 MW will come into play during those four-hour blocks when average temperatures are most likely to exceed 95 degrees Fahrenheit. Effective this year, RDFs are reviewed and adjusted based on the generator’s performance during an unannounced test.

“If the temperatures are over 95, we need to move this market away from the old zonal market rules and control area rules,” Calpine’s Randy Jones said. “You should not be doing testing around peaks.”

Austin Energy’s Barksdale English agreed with Jones, saying the RDF should be based on actual performance, not unannounced testing.

The recommendation has already been endorsed by the Wholesale Market and Reliability and Operations subcommittees. It will go to ERCOT’s Board of Directors in June for final approval.

NOGGR Tabled, Other Revision Requests Approved

The TAC unanimously approved a previously tabled revision request and several other change requests brought forward by its subcommittees. It also tabled a nodal operating guide revision request (NOGRR) that recommended a 25-MW annual-peak threshold to exempt distribution service providers from procuring designated transmission operator services from a third-party provider.

NOGRR 149 was developed last year to settle the noncompliant status of seven municipally owned utilities (MOUs), ranging in size from 9 to 21 MW. It was rejected by ROS and tabled by TAC, but the revision request’s proponents appealed.

GDF Suez’s Bob Helton, representing the Independent Generators segment, recommended tabling the NOGRR to allow ERCOT staff to answer several other questions. TAC Vice Chair Adrianne Brandt, of CPS Energy, asked that transmission service providers meet with the MOUs to further discuss the issue.

The committee approved:

NOGRR 151, aligning operating guides with changes made in NPRR 748 and providing consistency, transparency and clarification related to communication protocols;
NOGRR 153, creating a new process to maintain alignment of the energy emergency alert language between the protocols and nodal operating guides;
Nodal protocol revision request (NPRR) 752, clarifying the revision-request process protocol language to reflect current ERCOT practices; and
System change request (SCR) 788, updating the resource-limit calculator formula used to determine the generation-to-be-dispatched value.

Ögelman updated the TAC on NPRR 667, which he called an “odyssey” more than two years in the making. The revision request is designed to improve regulation-up and regulation-down service and replace RRS and non-spinning reserves with a combination of four new ancillary services.

ERCOT is hoping the Protocol Revisions Subcommittee (PRS) will endorse the NPRR in May, before bringing it back to the TAC.

“We believe 667 meets a lot of board objectives and market-design objectives,” Ögelman said, “but ERCOT is willing to wait on TAC’s final input on the issue.”

In March the PRS withdrew a similar revision request (NPRR 756) that would redesign the ancillary services market. Staff said at the time NPRR 667 was the better option.

Data Workshop Scheduled

The committee discussed ERCOT’s upcoming workshop on data reports, tentatively scheduled for May 20. The workshop is a result of a discussion at the March TAC meeting about how the ISO and its market participants exchange data and handle changes to reports. (See “TAC to Schedule Data-Exchange Workshop,” ERCOT Technical Advisory Committee Briefs.)

Ögelman said the workshop would focus first on changes to reports and how they impact market participants, and then the internal need for “some type of controls around [the reports] that give people comfort.”

“We want to explore more stable, different ways to interact without scraping data,” he said.

“I think this is an important step for us to take,” Citigroup Energy’s Eric Goff said. “It’s so critical to ensure everyone has reliable and robust access to all ERCOT data. Over the long run, I think it will be a significant improvement to the transparency of data.”

ERCOT staff said it is also working on an NPRR to improve the accuracy of its wind forecasts by synching them with the current operating plan for intermittent resources.

Stephenson noted market participants have seen “big swings” of about 175 MW during March and April, creating volatility in the market. She assigned the NPRR’s work to the Wholesale Market Subcommittee.

The WMS, Retail Market and Commercial Operations subcommittees all delivered their normal monthly status reports.

– Tom Kleckner

May 2, 2016

SPP RSC Briefs

SANTA FE, N.M. — SPP’s Integrated Marketplace continues to show growth and member benefits in its second year of business, SPP Vice President of Operations Bruce Rew told the Regional State Committee (RSC) last week.

Bruce Rew SPP VP of Operations - SPP regional state committee briefs — Rew *© RTO Insider*

Rew said 172 market participants — 110 classified as financial-only, 62 as asset-owning — are now registered for the Integrated Marketplace, comprising the day-ahead and real-time markets, a price-based operating-reserve market and a central balancing authority. He also said the markets delivered $380 million in net savings in the 12 months after they went live in March 2014 and $422 million in savings in 2015.

“We’re still providing a lot of benefits with optimized dispatch, even with natural gas prices under $2,” Rew said.

Part of the marketplace’s success stems from SPP’s growing wind capacity, currently 12,400 MW, with another 574 MW in the pipeline. The RTO, which previously had 50 MW of solar capacity, had an additional 140 MW register April 1, its first addition of solar in years, Rew said. The facilities will go online later this year.

Rew strayed from his presentation to note SPP had set two more wind energy records over the weekend, extending its wind peak to 10,989 MW on April 23 and its wind penetration level to 49.17% on April 24.

SPP has seen its generation profile change and become more diverse with the October addition of the Integrated System and its hydro and wind resources. The RTO set a new winter peak load of 37,412 MW on Jan. 18, 417 MW more than last winter’s peak.

Rew also noted that the day-ahead market was only delayed from posting once in the first quarter of 2016. The real-time balancing market has successfully solved 99.9% of all intervals, he added.

More market improvements are coming. Rew said the gas-electric harmonization project is still on schedule for a fall implementation, and the enhanced combined cycle project is expected to meet its March 2017 target. (See “Enhanced Combined Cycle Project Moves Forward,” SPP Board of Directors/Members Committee Briefs.)

CAWG Updates

The Cost Allocation Working Group (CAWG) updated the RSC on its work, including several issues which will come up for RSC and/or board votes in July.

Nebraska Power Review Board consultant John Krajewski said he hopes a new member cost-allocation review process will be ready for approval in July. He said the process should add consistency to the process used when new members are being considered or ask for changes to the Tariff.

“When we integrated Nebraska and the IS, there wasn’t a firm process to follow,” Krajewski said. “My impression was we flailed around as an RSC.”

Adam McKinnie, chief regulatory economist with the Missouri Public Service Commission, said the working group’s review of aggregate study waiver criteria will help the committee determine which transmission project costs are paid by companies purchasing transmission service and which are allocated to the SPP footprint. SPP’s aggregate study assesses which projects are necessary to sell transmission-service requests (TSR) to move energy around the SPP system, as well as who pays for those projects.

McKinnie pointed out that costs are initially assigned to the different purchasers once the study is complete, but if those purchasers meet certain criteria, a portion of those costs will be paid for by the region. The amount approved for base plan funding is the “safe harbor,” he said, but TSR purchasers who don’t meet the safe harbor’s three criteria can ask for a waiver.

The CAWG is considering criteria that would limit a utility’s designated resource to no more than 125% of its forecasted load if it’s granted a TSR, ensuring base-plan funding is not used for “resources which are unnecessary or uneconomic.”

“The goal is to make sure only designated resources that are needed or close to forecasted load receive the waivers,” McKinnie said.

RSC Vice Chair Steve Stoll (Missouri PSC), Chair Patrick Lyons (N.M.-Public-Regulation-Commission) - SPP regional state committee briefs — Left to right: Stoll, Lyons, Albrecht *© RTO Insider*

Stephen Stoll, a commissioner with the Missouri PSC and chair of the Regional Allocation Review Task Force, told the RSC his group had finalized the language for a new business practice implementing each of the remedies recommended in the 2012 RARTF report. The task force intends to bring the revision request for MOPC and board approval in July.

The business practice is designed to “lay the foundation for documenting the potential [regional-cost allocation review] remedies and clarify the process … implementing [an RCAR] remedy.” The task force is responsible for defining the analytical methods used to review the “reasonableness” of the regional-allocation and zonal-allocation methodologies.

The committee also received a status report from the Transmission Planning Improvement Task Force and an update on the 2016 Integrated Transmission Plan’s 10-Year Assessment and report (See related story, SPP Board of Directors Briefs.)

MISO Settlement Funds Held Up

COO Carl Monroe told the committee that SPP has received funds from the recent $9.6 million settlement with MISO, but that protests have delayed distribution of the money.

MISO agreed to the payment to reimburse SPP and impacted members for its use of their transmission systems since 2014. (See FERC OKs MISO-SPP Transmission Settlement.)

On Jan. 27, SPP proposed a new Tariff Attachment AU to govern the distribution of the settlement revenues. The City of Lincoln, Neb., and four wind farms protested in February.

Lincoln said that SPP’s proposal to create a new revenue allocation methodology is unnecessary, and that the RTO should allocate the revenues under the rules in Tariff Attachment L.

In its answer, SPP said that Attachment L is not applicable to the settlement revenues. Contrary to Lincoln’s protest, SPP said it is not providing point-to-point (PTP) transmission service but available system capacity (ASC) usage.

PTP service is charged based on the amount reserved, regardless of actual scheduled usage, and includes a point of receipt and a point of delivery on the SPP system. ASC usage is charged based on actual usage of the SPP and joint parties’ transmission systems as determined by the flow impact of MISO market dispatches between its North and South regions. (The joint parties are Associated Electric Cooperative Inc., PowerSouth Energy Cooperative, Southern Company Services, Tennessee Valley Authority, Louisiana Gas and Electric and Kentucky Utilities.)

SPP also rejected the wind farms’ complaint that its proposal would circumvent the Z2 revenue crediting process, which gives upgrade sponsors a share of revenues received by SPP when the transmission upgrades they funded are used by others. “Attachment Z2 of the SPP Tariff is simply not applicable to the [joint operating agreement] settlement revenues,” SPP said.

On March 25, the commission accepted SPP’s proposal in part and set the docket for hearing and settlement procedures, saying there were factual issues in dispute that could not be resolved based on the record before it (ER16-791).

The commission rejected SPP’s proposal to reimburse $456,000 spent by some transmission owners on legal expenses in the SPP-MISO dispute. “SPP has not provided any commission precedent permitting a regional transmission organization to reimburse certain stakeholders for legal expenses, nor has SPP shown that the transmission owners that incurred the legal expenses represented the interests of SPP and its transmission customers rather than their own interests,” FERC said.

The first settlement conference was held April 21, with a second scheduled June 16.

In the meantime, Monroe said, SPP has asked FERC for permission to distribute the funds to members who signed on to the settlement agreement. “We will be distributing those funds based on our proposed distribution,” he said, but he noted the distribution would be to entities that can make refunds to SPP “if the settlement is different than … proposed.”

‘Where Policy Issues Go to Die’

Denise Buffington, director of energy policy and corporate counsel with Kansas City Power and Light, asked Monroe whether the MOPC’s recent decision to develop a business practice to address non-Order 1000 seams projects was the right mechanism to resolve FERC’s rejected Tariff revision. (See “SPP Pondering ‘One-Offs’ as Potential Seams Projects,” SPP Markets and Operations Policy Committee Briefs.)

“It feels like a business practice is a place where policy issues go to die,” Buffington said.

“We’ll debate that as we go through the business practice,” Monroe assured her. “No one wanted to go through a FERC refiling. The question we’re still trying to address is whether there’s a gap … the business practice is going to have to deal with where the gap is.”

— Tom Kleckner

May 2, 2016

NYISO Plans Change to Ranking of Projects

By William Opalka

RENSSELAER, N.Y. — NYISO is proposing to change the way stakeholders prioritize internal projects, effective with the 2017 priority list.

The ISO reviewed its proposal at Wednesday’s Management Committee meeting, nearing the end of a process that began in the Budget and Priorities Working Group last September. “This is based on stakeholder feedback,” NYISO senior manager Ryan Smith said.

The projects include software and product development and NYISO capital expenditures.

NYISO scoring uses objective criteria that reflect strategic alignment, expected outcomes, risks and ability to execute. The stakeholders score projects based on their organizational priorities.

Among the proposed changes is the exclusion of mandatory and continuing projects from priority scoring. Stakeholders, who rank projects by assigning them shares of 100 voting points, would no longer have to “waste” their votes on projects that are already considered mandatory or are already under development, the ISO said.

NYISO also is proposing the use of sector-weighted scores in addition to raw scores. Affiliates and nonvoting entities would be excluded from weighted scoring but would be included in the raw scores.

Another change would provide cost and benefit information in advance of the stakeholder scoring deadline.

The timeline for drawing up the 2017 list includes identification of candidates through mid-June, followed by prioritization and evaluation by the end of July. That would be followed by recommendations in August, with final decisions made in the fall during NYISO’s annual budget process.

Project expenditures have averaged about $25 million annually in recent years, Smith said.

The changes are expected to be brought to a vote at the June board meeting.

May 2, 2016

Federal Briefs

EPA announced that rules covering methane leaks from new oil and gas wells will come out soon, but the agency would give no guidance on when rules covering existing wells would be released.

The agency said it is gathering data on existing wells before developing the rules. The Obama administration has put the rules at the top of its priority list because of the effect of methane on climate change.

“We have been moving in a very methodical manner to address pollution in ways that withstood legal challenges and are making a difference on the ground, and that is what we’re doing,” said Janet McCabe, head of EPA’s Office of Air and Radiation.

More: The Hill

NRC Approves Early Permit For Possible 4th Salem Reactor

The Nuclear Regulatory Commission’s Atomic Safety and Licensing Board approved preliminary documentation for the commission to issue an early site permit for a possible fourth nuclear reactor at PSEG Nuclear’s Artificial Island complex in New Jersey.

Although the company hasn’t yet committed to constructing a fourth reactor, it is pursuing the permit for planning purposes. If issued, the permit would be good for 20 years.

More: The Philadelphia Inquirer

Geological Survey Says Turbines, Sandhill Crane Can Coexist

Wind energy sites in southern states are unlikely to have a significant negative effect on the migratory patterns of the sandhill crane, according to a report from the U.S. Geological Survey.

“The current placement of wind energy towers in the central and southern Great Plains may have relatively few negative effects on sandhill cranes wintering in the region,” the study concluded. Among the states included in the review were Texas, Oklahoma, Kansas and New Mexico, which serve as temporary habitats for the cranes during their migration south from Canada and northern states.

More: Times Record News

EPA to Reimburse States, Tribes For Gold King Mine Spill

EPA said it will reimburse state, local and tribal governments for the estimated $1 million they spent on environmental costs after the agency accidentally caused a massive spill of mine wastewater in Colorado last August.

The agency is also considering declaring the Gold King Mine a Superfund site, which would make it eligible for additional federal cleanup dollars.

A crew working for EPA accidentally breached a wastewater holding area, releasing 3 million gallons of water containing lead, arsenic, copper and other pollutants. The tainted water flowed downstream through Colorado to New Mexico and Utah. The affected area included land owned by the Southern Ute and Navajo Nation tribes.

More: The Associated Press

Ex-NRC Commissioner: Licensing Process Hinders New Reactor Investment

Former Nuclear Regulatory Commissioner Jeffrey S. Merrifield said the commission’s current step-by-step licensing process for new nuclear reactor technology leaves advanced design developers with little information to go on and is hindering investment into research and development.

“One of the disadvantages of the current system is it’s sort of all or nothing,” said Merrifield, chairman of the Nuclear Infrastructure Council’s Advanced Reactors Task Force. “You have to put in your license application and wait a very long period of time to determine whether the NRC is going to find that to be acceptable.”

Merrifield made his comments at a House Energy and Commerce subcommittee hearing on Friday. As an example of a good model for NRC, he pointed to the Canadian Nuclear Safety Commission’s process, which has “discrete milestones” that “provide an early regulatory signal” of possible approval that costs project developers about $5 million, much less than required under current NRC procedures.

More: Morning Consult

Texas Company Applies for Interim Nuclear Waste Permit

Waste Control Specialists, in partnership with France-based AREVA, has applied to the Nuclear Regulatory Commission to store used nuclear fuel and other nuclear waste in Andrews County, Texas. The company’s design envisions a facility able to store 40,000 metric tons of used fuel, with an operational date of 2021. It would remain open for 40 years.

“Establishing an economically viable solution for used fuel management in the United States is vital to sustaining and advancing nuclear energy,” said Greg Vesey, senior vice president of AREVA TN Americas.

Political and industry leaders have been unable to devise a permanent storage facility for the nation’s roughly 70,000 metric tons of accumulated spent fuel and radioactive byproducts from nuclear reactors. In April, Holtec International announced plans to open a $5 billion consolidated interim storage facility in New Mexico, with a life span of 100 years. Holtec said it will apply for its license by the end of the year.

More: Power Magazine; The Texas Tribune

California Senate Demands DOE Remove San Onofre Waste

The California Senate is demanding that the U.S. Department of Energy remove nuclear waste stored at the retired San Onofre nuclear generating station. The oceanfront plant has been shut down since a leak in a steam generator convinced owner Southern California Edison that it made no economic sense to restart the two units.

The Senate resolution calls on President Obama and the U.S. House of Representatives to approve a bill that would call for consolidation of all nuclear waste being stored on plant sites.

“It’s way past time for the federal government to move the nuclear waste stored at San Onofre to a location away from densely populated and environmentally sensitive areas,” said California Sen. Patricia Bates. “I’m pleased that my state Senate colleagues have endorsed my call to Washington D.C. to approve pending legislation that would help make Orange and San Diego County residents safer.”

More: City News Service

NRC Clears Environmental Review Of Suspended Bell Bend Project

The Nuclear Regulatory Commission last week declared that there are no environmental issues that would hold up the issuances of a combined license for the proposed Bell Bend nuclear station project near Harrisburg, Pa., even though the project is no longer active.

In 2008, PPL, which spun off its generation assets into Talen Energy, applied for the license, which launched the environmental review. But last year, the designer of the project’s proposed reactor, AREVA, asked NRC to suspend the safety review. AREVA was to design a third-generation light-water reactor for the project.

The AREVA request put the design certification review on hold, but the environmental review continued. There is no word if the project will start up again.

More: Nuclear Street

TVA’s Bellefonte Nuke Plant up for Sale

The Bellefonte Nuclear Generating Station, the Tennessee Valley Authority’s never-operational plant near Hollywood, Ala., is going on the market.

TVA halted construction in 1988 on two incomplete 1,256-MW pressurized water reactors on the site. TVA is considering a sale of the entire 1,600-acre complex and is conducting a webinar open to the public to discuss the possible sale.

More: The Associated Press

May 2, 2016

PJM Markets and Reliability and Members Committees Briefs

WILMINGTON, Del. — The Markets and Reliability Committee last week deferred voting on a problem statement and issue charge to study the challenges of the pseudo-tie requirement for external Capacity Performance resources. Staff will narrow the scope of the proposal and return to the committee in May.

Stu Bresler, PJM (copyright RTOInsider) - MRC and members committee — Bresler © *RTO Insider*

PJM has been working on temporary solutions to resolve operational and reliability issues, but it wants to decide on a long-term solution in time for the 2017 Base Residual Auction.

In order to participate in PJM’s capacity market, external resources are subject to pseudo-tie requirements. PJM has encountered some issues with the construct, however, including compliance risks, congestion management challenges, transmission service evaluation issues and operational impacts on neighboring systems.

Stu Bresler, vice president for market operations, said that a study such as the one proposed by the problem statement and issue charge could lead to changing the qualifications for granting transmission service into PJM.

A number of stakeholders expressed concern that if the deliverability standards are altered, they might preclude units currently allowed to deliver capacity into PJM from being able to do so in the future.

Bresler assured members that any changes would be applied “prospectively” and would not affect capacity that already has cleared.

However, that did not assuage the concerns of members including Ed Tatum, of American Municipal Power, who worried that generators may invest in upgrades only to find they are no longer eligible to deliver capacity in future delivery years.

“You need to have certainty,” he said. “We’re talking about making investments in units.”

PJM Prepares for FERC Directive on MOPR

Bresler told the MRC that PJM wants to schedule meetings so that members are prepared if FERC directs the RTO to change its minimum offer price rule (MOPR) as a result of Ohio regulators’ controversial approval of power purchase agreements for FirstEnergy and American Electric Power generating units. (See PJM: MOPR Could be Improved, but not by BRA.)

Eleven generating companies had asked FERC to expand the MOPR, which currently applies only to certain new resources, saying they feared that the Ohio PPAs could lead to below-cost offers from existing resources.

PJM agreed that the MOPR should be changed to counter subsidized offers from existing generators, but it asked FERC not to order changes before next month’s BRA.

“Putting rules of this magnitude in place in such a short timeframe could lead to significant unintended consequences. The best course of action is to kick it to the stakeholder process, allow us to thoroughly vet the issue and allow us to come back in time for the next auction,” Bresler said, paraphrasing PJM’s filing.

“Having suggested that, we came to the realization that if we waited for a response from FERC before we started the ball rolling, it would put us even further behind the eight ball,” he said. “We thought it would be prudent to get some meetings on the calendar.”

Assuming FERC respects PJM’s wishes and does not order changes for the upcoming auction, the first educational meeting would be scheduled for late May or early June.

In two other dockets, FERC on Wednesday rescinded the affiliate-sales waivers held by AEP and FirstEnergy, requiring federal review of the PPAs. (See FERC Rescinds AEP, FirstEnergy Affiliate Sales Waivers; Will Review Ohio PPAs.)

Changes to Manuals 12, 19 Approved

Members endorsed the following manual changes:

Manual 19: Load Forecasting and Analysis. Revisions remove outdated rules for legacy air conditioner and water heater cycling programs and correct formulas for end-use weather variables.
Manual 12: Balancing Operations and Tariff changes incorporate business rules of dynamic transfers.

Settlement Method for Demand Response Adopted

The committee endorsed a new method for measuring emergency demand response. It changes the emergency energy default customer baseline (CBL) from the hour before to the current default economic CBL. (See “Members Endorse New Way to Measure Emergency DR,” PJM Market Implementation Briefs.)

GDECS Definitions and Clarifications Endorsed

The MRC and the Members Committee approved the nonsubstantive reorganization and relocation of definitions recommended by the Governing Documents Enhancement and Clarification Subcommittee (GDECS).

As part of its consent agenda, the MC also approved an additional 11 items recommended by the GDECS.

Over 16 objections, the MC also endorsed the definition of capacity import limit. Members had expected to vote on a friendly amendment to the definition, but that was withdrawn before the meeting.

MRC First Readings

The MRC heard the proposed charter for the End of Life Senior Task Force, created in March to develop ways to provide more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan.
Members were informed of a proposed revision to the charter of the Energy Market Uplift Senior Task Force to include the review of virtual transaction rules.
PJM’s Dave Egan presented the recommendations of the Earlier Queue Submittal Task Force. The changes would require interconnection customers to provide more documentation earlier to ensure consideration of their projects. (See “Stricter Rules Proposed for Queue Submittal Process,” PJM Planning Committee and TEAC Briefs.)
Barry Trayers of CitiGroup Energy proposed adding the phrase “Any transactions that PJM staff determine would not benefit from delaying until the [equivalent forced outage rates] are published” to the “Replacement Resources” section of Manual 18.
A proposed charter was presented for the Seasonal Capacity Resources Senior Task Force, which will study how such resources may participate in the Capacity Performance model in the 2020/21 delivery year and beyond.
Dave Anders presented some minor word changes to a previously approved problem statement and issue charge to study distributed energy resources’ path to PJM markets. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM MRC & Members Committee Briefs.)

– Suzanne Herel

May 2, 2016

MISO Informational Forum Briefs

Decreased load, strong wind output and declining gas prices in March translated into MISO’s lowest prices since 2009, according to the RTO.

Real-time and day-ahead energy prices averaged $19.85/MWh and $19.44/MWh, respectively, tumbling by more than 30% compared with last March.

“These are the lowest levels we’ve seen in about seven years,” said Shawn McFarlane, MISO’s executive director of strategy and enterprise risk management.

Load for the month peaked at 85 GW on March 1. Monthly average load declined by 9% from February and 5% from a year earlier.

Gas prices continued to fall, averaging $1.80/MMBtu for the month at Chicago Citygate and $1.67/MMBtu at Henry Hub. Gas-fired generation accounted for 31% of MISO generation, compared with 23% a year earlier.

Renewable energy output reached 4,186 GWh, nearly doubling the monthly target and exceeding MISO’s goals for the sixth straight month.

McFarlane said the “usual outbreak of severe weather in springtime” began as expected in March, with heavy rainfall in eastern Texas flooding some substations. The season also brought an expected increase in maintenance outages.
March’s generation queue status metric remained a point of concern due to restudies stemming from withdrawn projects.

“We’re still obviously using our current [queue] process until a [new] plan can pass muster,” McFarlane said. (See MISO Queue Changes on Hold Pending Technical Conference.)

MISO’s unit commitment efficiency metric was also in “concern/monitor” status for the month because of a March 22 incident in which a unit failed to shut down in time based on its minimum run time and economic commitment period.

MISO Could See Fewer Legal Filings in 2016

MISO’s volume of FERC filings this year is so far trending downward, Deputy General Counsel Eric Stephens said.

The RTO has made 147 filings year-to-date, he said last Tuesday.

“We’re thinking that may put us on pace to file 450 to 500 filings this year,” representing a significant decrease from the 584 filings made in 2015, Stephens said.

Stephens reminded stakeholders to submit feedback to the RTO on its planned “continuous improvement” Tariff filing, which will seek to clean up provisions related to competitive transmission development and the RTO’s selected developer agreement.

He said the filing contains mostly minor changes in wording, but it does include one substantive item: MISO is seeking FERC permission to extend from 30 days to 60 the time between board approval of the annual MISO Transmission Expansion Plan and requests for proposals for transmission projects. The RTO is targeting an early May filing date for the revisions.

— Amanda Durish Cook

May 2, 2016

CPV Power Plant Ensnared in Federal Corruption Probe

By William Opalka

A former top aide to New York Gov. Andrew Cuomo is under federal investigation for his dealings with companies with business before state government, including power plant developer Competitive Power Ventures, according to the New York Daily News.

cpv valley project rendering (CPV) - andrew cuomo — CPV Valley Energy Center Project Rendering *Source: CPV*

The report, citing unnamed sources, said CPV hired Joseph Percoco as a consultant. He and several other people are being investigated by Preet Bharara, U.S. attorney for the Southern District of New York, for improper lobbying and undisclosed conflicts of interest. Percoco made $169,000/year as Cuomo’s executive deputy secretary, according to the paper.

Percoco received payments from the companies while he served as Cuomo’s campaign manager in 2014, according to the Daily News. He returned to the state payroll for about a year after the election.

According to the paper’s sources, those payments were legal; the investigation reportedly concerns whether the payments went unreported, and if Percoco was involved in state business that involved CPV and another company that hired him. Percoco left the Cuomo administration to take an executive position at Madison Square Garden in January.

CPV is building the 650-MW natural gas-fired Valley Energy Center in Orange County, north of New York City. The New York Public Service Commission granted a certificate of public convenience and necessity for the project two years ago (10-E-0501). The plant broke ground last year, and its addition to the state’s power portfolio impacted transmission planning, as it will help relieve downstate constraints. (See NYPSC Staff Narrows Transmission Alternatives.)

A CPV spokesman did not return calls seeking comment.

In a recent filing with the PSC, the company said it sought to keep its structural drawings private because the plant site has been the focus of weekly protests.

Bharara served a subpoena on the governor’s office on Friday. The Cuomo administration released a statement saying, “We take violations of the public trust seriously and we believe these issues must be resolved by further investigation by the U.S. attorney. In the meantime, and as the program operates on a daily basis, the governor has ordered an immediate full review of the program.”

The governor also ordered state employees to suspend any discussions of regulatory or other matters with CPV, the Daily News reported.

The primary focus of the investigation is the so-called Buffalo Billion economic development program championed by Cuomo. Bharara’s probe began last fall. A centerpiece of that program is $750 million in direct state aid and tax credits to SolarCity, which is building a 1-GW solar panel factory, the largest of its kind in the Western Hemisphere, according to the state.

Bharara has prosecuted and convicted several state legislators in recent years in corruption probes. Last December, he won convictions of the Democratic Speaker of the Assembly and the Republican Senate Majority Leader.

May 2, 2016

NYISO: FitzPatrick Closure will not Harm Reliability

By William Opalka

Contrary to an earlier analysis, the closure of Entergy’s FitzPatrick nuclear plant will not leave New York short of generation in 2019, NYISO says.

fitzpatrick, nyiso, reliability — Fitzpatrick Nuclear Plant *Source Entergy*

In a report in February, the ISO had said the loss of the 882-MW plant on Lake Ontario would leave the state short at least 325 MW in three years. (See Fitzpatrick Closure Could Leave NY Generation Short.)

But an updated analysis, using a lower load forecast, found no cause for alarm. According to NYISO’s 2016 Gold Book, the coincident peak load expected for 2020 is 34,019 MW, a decrease of 843 MW from the ISO’s 2015 assessment.

“The most recent long-term forecast data shows a decline in both summer peak demand and annual energy usage,” NYISO spokesman David Flanagan said. “There are several contributing factors, including slower peak load growth in the downstate region; slower economic growth after 2020, based on Moody’s current outlook; and impacts of energy-efficiency initiatives, on-site generation and distributed resources.”

Both studies assumed 1,995 MW of generation will leave the resource base by 2020, including FitzPatrick and Exelon’s R.E. Ginna nuclear plant in 2017. (See FERC Accepts Ginna Settlement.)

Entergy announced late last year that it would close FitzPatrick because of low power prices. Based on the previous analysis, NYISO had initiated an expedited “gap solution” process in which the RTO solicits proposals from market participants outside of its usual two-year cycle to address an identified reliability need. Based on the new analysis, that process has been withdrawn.

Entergy has rebuffed New York’s efforts to keep the plant operating, including a proposed financial mechanism to subsidize carbon-free generation, as insufficient and insisted FitzPatrick will close in January. (See New Lifeline for FitzPatrick Nuclear Plant.)

May 2, 2016

MISO Advisory Committee Briefs

MISO’s Advisory Committee has narrowed down the list of topics it expects to include in the first version of its 2016 priorities document.

The committee’s current draft lists five priorities, including seams optimization, infrastructure development, grid technology, the Clean Power Plan and gas-electric coordination. The document is intended to guide MISO parent entities in their decision-making.

“This document is not set in stone — it’s a living, breathing document,” Audrey Penner, Advisory Committee chair, told stakeholders during an April 27 meeting. “If we come out of this all a little bit unhappy … then we have achieved success, as far as I’m concerned.”

In response to multiple requests for greater prioritization of market issues, Penner said the committee could either create separate priorities covering improved markets and price formation, or fold market considerations into an existing priority.

Kent Felix, with the Power Marketers sector, suggested giving each parent entity its own set of priorities. But Advisory Committee Vice Chair Tia Elliott said more than three to five priorities would create too many areas of focus.

DeWayne Todd, with the End-Use Customers sector, said he could support what was already laid out, but he thought some of the priorities were too narrowly defined. He said the Clean Power Plan and gas-electric coordination were “too tactical” to be overarching topics.

Paul Kelley, with the Transmission Owners sector, said gas-electric coordination deserved a spot on the list because of MISO’s rapidly changing generation mix and the potential for additional FERC rulings to enhance alignment of the two industries. (See FERC OKs MISO Use of Eastern Standard Time in Day-Ahead Market.)

The Competitive Transmission Developers sector asked to include refinements to the competitive solicitation process, while the Independent Power Producers sector proposed removing gas-electric coordination in favor of a market performance and enhancement priority.

The Transmission Owners sector asked for the inclusion of a sixth “Other” category to assess the criteria and costs of market efficiency projects, consider implementation of FERC market-related initiatives and evaluate the competitive transmission development process.

The Power Marketers sector proposed a complete overhaul of the priorities document, suggesting that a price formation priority replace grid enhancement, an “enhance operations” priority replace gas-electric coordination and removing the federal rule priority in favor of a “regulation implementation” priority, with a subcategory dedicated to developing new market products.

The Public Consumer Advocates and Coordinating Members sectors, on the other hand, said the current draft was acceptable as is.

Penner asked for feedback by May 11 to inform a final document, which should be completed ahead of a vote at the May 25 committee meeting.

Economist Joins MISO Finance Subcommittee

The Advisory Committee elected Pradeep Sircar to represent consumer advocates in MISO’s Finance Subcommittee. Sircar, an applied economist with the Indiana Office of Utility Consumer Counselor, currently analyzes the MISO and PJM markets and has previously worked at MISO and CAISO. In his 30-plus years of experience, Sircar also worked with the Nevada Public Utilities Commission, Iowa Utilities Board, Ohio Edison and Northern Indiana Public Service Co.

— Amanda Durish Cook