CAISO Monitor Seeks Congestion Revenue Rights Auction Reforms

By Robert Mullin

CAISO paid congestion revenue rights holders $27 million more than it took in from CRR auctions during the first half of the year, according to the ISO’s Department of Market Monitoring.

That equates to 63 cents in auction revenues for every dollar paid out, leaving California electricity consumers to foot the difference — which mostly goes to speculators, the Monitor says.

The department wants the ISO to address the issue by eliminating or reforming the auction process.

“There’s a shortfall between payments and revenues in the auction, and this money is really ultimately paid by the ratepayers in the market,” Gabe Murtaugh, a department senior analyst, said during a Sept. 14 call to discuss the department’s second-quarter market performance report.

CAISO congestion revenue rights — The graph shows that payments to congestion revenue rights holders consistently exceed the amounts taken in by the ISO during auctions.

The Monitor reasons that ratepayers — who ultimately bear the costs for transmission access charges paid by load-serving entities — are entitled to receive the revenues from transmission.

“When auction revenues are less than the payments transferred to other entities purchasing congestion revenue rights at auction, the difference between auction revenues and congestion payments represents a loss, which is paid out from the day-ahead congestion rent,” the department’s quarterly report explained. “The losses therefore cause ratepayers, who ultimately pay for the transmission, to receive less than the full value of their day-ahead transmission rights.”

Financial traders are the biggest beneficiaries of the current CRR market design, the Monitor has found. During the first half of 2016, those companies made $22.7 million in profits, more than doubling their investments as they paid 49 cents into the ISO’s auctions for every dollar earned.

Over the same period, power marketers and generators took in about $3.9 million and $800,000, respectively, paying 82 and 85 cents for every dollar of congestion revenues earned.

This year’s mismatch extends a pattern that has persisted for nearly five years, Murtaugh said. Since 2012, CRR payments have exceeded auction revenues by more than $500 million.

It all adds up to a need for a change in how the ISO administers the CRR process, the Monitor contends.

One specific recommendation is that the ISO should end the practice of auctioning off excess transmission capacity to third parties after LSEs have received their CRR allocations.

“With this approach, the ISO could still run a market for congestion revenue rights,” the Monitor said. “However, this market would be run only with bids voluntarily submitted by various participants willing to essentially buy or sell congestion revenue rights.”

In other words, the only CRRs available to market would be those allocated to LSEs. CRRs would only be sold if there was a market participant willing to take on the obligation to pay congestion revenues at the market clearing price, thereby reducing ratepayer exposure to market shortfalls.

“In this market, any entity that values hedging against locational price differences, such as generators or marketers, could submit bids to purchase congestion revenue rights,” the Monitor said. “Financial entities, other participants willing to sell hedges or entities wishing to speculate on locational price differences could submit bids to sell congestion revenues rights.”

The Monitor said it is prepared to work with the ISO and stakeholders on additional options to change the CRR market and noted that the ISO’s management is considering adding the issue to its stakeholder initiative catalog this fall.

September 19, 2016

PJM Attempting to Usurp Market Mitigation Role, Monitor Says

By Rory D. Sweeney

PJM is trying to usurp the Independent Market Monitor’s authority to regulate fuel-cost policies and consequently increasing market participants’ ability to exercise market power, the Monitor argued in a protest Friday (ER16-372).

PJM’s proposed plan for evaluating fuel-cost policies, filed Aug. 16, “would substantively change the roles of PJM and the Market Monitor in the review of offers for market power in a manner inconsistent with the Tariff’s specifications of roles,” IMM staff wrote. “Participants will have the ability and incentive to submit inaccurate cost-based offers.”

The debate over the rules governing fuel-cost policies stems from a 2015 FERC order requiring the RTO to allow day-ahead offers that vary by the hour and the ability of generators to update offers in real time. (See Heeding Stakeholders, PJM Reduces Proposed Fuel-Cost Penalties.)

The Monitor said that daily offers limited generators’ “ability to exploit real-time constrained conditions.” The switch to hourly offers, it said, requires “increased rigor” in mitigation design and the implementation of the three pivotal supplier test in addition to fuel-cost policies.

Other responses to PJM’s filing largely supported the RTO’s effort to develop hourly offer rules, but they differed on how fuel-cost policies should be handled and what role the Monitor should play.

‘Define the Roles’

The Pennsylvania Public Utility Commission and the Delaware Public Service Commission said in a joint filing that “PJM’s [fuel-cost policies] proposal undermines the Independent Market Monitor’s role in detecting and addressing market power concerns” and urged FERC to adopt the Monitor’s standards.

In a joint filing supporting PJM’s proposal, American Electric Power, Dayton Power and Light, FirstEnergy, Duke Energy, Buckeye Power and the East Kentucky Power Cooperative asked the commission to “plainly define the respective roles” of PJM and the Monitor in the process.

“Market sellers are squarely in the middle of a perfect storm created by ambiguous governing documents, new commission directives and a complete lack of clarity concerning the role of the IMM,” the group wrote. “The result is untenable risk associated with submitting cost-based offers without approved fuel-cost policies. Failing to act timely, or at a minimum to preserve the status quo while the commission deliberates, will perpetuate an already fraught state of affairs.”

Dominion Virginia Power reiterated those sentiments in its filing, asking “that the commission establish final authority with one entity.”

The Organization of PJM States Inc. asked FERC to view the docket in a larger context. “Discounting the IMM’s current role could provide a signal to resources that they would no longer be held fully accountable to IMM oversight, potentially eliminating the proper incentive to submit accurate cost-based offers,” OPSI wrote. “The commission should consider the broad implications of approving any filing that usurps the IMM’s existing market power authorities.”

The American Petroleum Institute focused on the structure of the policy itself, saying the rules “need to provide generators some degree of flexibility to procure fuel in the lowest cost manner.” Specific rules about how to procure fuel “may restrict generators in a way that could lead to higher consumer costs.”

API also protested PJM’s proposal that all policies on which the RTO and the Monitor can’t agree on should be referred to FERC’s Office of Enforcement. The group called for a dispute-resolution process instead.

No ‘Bright Line’

The PJM Power Providers Group agreed procurement practices shouldn’t be dictated. “The purchasing of fuel for power generation is a complicated and thoughtful piece of any generator’s business strategy,” P3 wrote. “PJM and the IMM should not attempt to replicate the market or impose a formulaic evaluation on generators, as such a task would prove nearly impossible and more likely lead to chaos during times of system stress.”

Dominion agreed that PJM’s proposal is too restrictive. Fuel-cost policies should not be “a pre-existing, bright-line formula for all market conditions,” Dominion wrote. “This expectation is unrealistic and made more unreasonable by PJM’s failure to first require consultation regarding suspect cost-based offers before they are deemed to be not in compliance with a resource’s fuel-cost policy.”

The company called for a system similar to ISO-NE’s, in which its Internal Market Monitor estimates a competitive offer that creates a “reference price” against which all market offers are compared. It also asked that PJM’s proposed penalty — requiring units without an approved policy to submit an offer of $0 — be replaced with a less punitive option and that companies not be required to submit a policy for each type of fuel at a unit, estimating it would need to maintain more than 100 separate policies.

No matter what FERC’s decision, it should be made quickly, P3 urged. “Every winter that passes without hourly offer flexibility is a winter in which the market is less efficient, suppliers are exposed to inadequate cost recovery and reliability is potentially” compromised, the group wrote.

Monitor’s Proposal

The Monitor proposed a clear delineation between the responsibilities of PJM, which would conduct a compliance review with IMM input, and the Monitor, which would conduct a market-power review without PJM involvement. The Monitor said its review will ask that policies are algorithmic, verifiable and systematic. They would need to show:

a set of defined, logical steps;
a fuel price that can be calculated by the Monitor after the fact with the same data available to the generation owner at the time the decision was made and documentation for that data from a public or a private source; and
a standardized way for calculating fuel costs including “objective triggers” for each method.

PJM proposed a joint review that it would control with input from the Monitor. The RTO’s proposal creates “a critical flaw” because it doesn’t “preserve the Market Monitor’s role in market-power reviews and to tie the consequences for noncompliance to that review,” the Monitor said.

September 19, 2016

Federal Briefs

Energy Secretary Ernest Moniz said that Congress should pass tax credits to incentivize clean-coal projects, preserving coal’s viability as a fuel.

The comments came as Moniz, speaking at the Mid-Atlantic Region Energy Innovation Forum in West Virginia, deflected charges the Obama administration has treated coal unfairly. “Plain and simple, ‘War on Coal’ is not what this administration has as a policy or has done,” he said. “It starts with — make no bones about it — we and the world are heading to a low-carbon future.”

But he still sees coal as an important fuel source going forward. “Getting the tax credits this year would be a very, very big deal,” Moniz said. “And having the tax credits in place in a trajectory for carbon reduction, in my view, is what the investment community needs.”

More: The Associated Press

Senate Passes Water Bill with Coal Ash Amendment

The Senate passed a water resource infrastructure bill with an amendment that would give states more authority over permitting and the enforcement of coal ash disposal.

The Water Resources Development Act of 2016, which authorizes $10.6 billion in water project funding, also adjusts the Solid Waste Disposal Act to give states authorization to institute their own coal ash disposal rules instead of EPA’s rules. The state standards would have to be “at least as protective” as federal standards.

Environmental groups said the new amendment could result in confusion. “The proposed legislation could effectively remove the EPA rule’s federal minimum stands, which could lead to a patchwork of regulatory requirements,” the Environmental Integrity Project and the Waterkeeper Alliance said in a letter.

More: Argus Media

NJ, Fed Agencies File Critical PennEast Comments with FERC

Ahead of Monday’s deadline, several federal and New Jersey government agencies filed comments with FERC last week criticizing the commission’s draft environmental impact statement on the proposed PennEast Pipeline.

Among the federal agencies that filed comments were the U.S. Fish and Wildlife Service, the National Park Service and EPA, the last of which concluded the proposed 118-mile pipeline would cause “significant adverse environmental impacts.” The agencies also said the draft EIS omitted a significant amount of information.

The New Jersey Department of Environmental Protection and the New Jersey Rate Counsel were also critical, with the latter saying the developers failed to justify the need for the pipeline. The $1.12 billion project, being developed by a consortium of several companies, would deliver shale gas from Northeastern Pennsylvania into New Jersey.

More: NJ Spotlight

House Passes Advanced Nuclear Technology Framework Bill

The House of Representatives last week passed a bill that directs the Nuclear Regulatory Commission to create a regulatory framework and criteria that would allow for the licensing of advanced nuclear reactors.

The Advanced Nuclear Technology Development Act of 2016, sponsored by Reps. Bob Latta (R-Ohio) and Jerry McNerney (D-Calif.), requires the Energy Department and the commission to collaborate on the licensing process in order to provide certainty to developers of the technology, which includes molten salt reactors and supercritical water reactors.

“This bill will help provide certainty for innovators and entrepreneurs who are seeking to develop and license the next generation of nuclear technologies,” House Energy and Commerce Committee Chairman Fred Upton (R-Mich.) said. “We should ensure that the Nuclear Regulatory Commission has the expertise and resources to review and license the latest in advanced reactor technologies, and this bill does just that.”

More: House Energy and Commerce Committee

Tribe Wants Review of Enbridge Settlement

A Michigan Native American tribe said it was never consulted on an agreement between Enbridge and EPA in which the company will pay a $61 million fine and spend $110 million in pipeline upgrades to settle claims relating to the 2010 oil spill in the Kalamazoo River.

Part of the settlement calls for upgrades to Enbridge’s Line 5, which carries crude oil beneath the Straits of Mackinac. The Grand Traverse Band of Ottawa and Chippewa Indians, which has fishing rights to the straits under an 1836 treaty, said it was never consulted on the settlement terms.

An attorney representing the tribe said it would have called for a full environmental review of Line 5. Any actions Enbridge takes on that line now are not covered by review requirements. The tribe wants the Kalamazoo spill settlement reopened for review. A Justice Department spokesman said the objection is under review.

More: Inside Climate News

September 19, 2016

Company Briefs

Raymond Hill, Barney Rush and Vickie VanZandt last week were re-elected to three-year terms on the ISO-NE Board of Directors, effective Oct. 1, 2016.

Hill joined the board in 2010, Rush joined in 2013 and VanZandt joined in 2011.

More: ISO-NE

NRG Wins Bid for SunEdison Renewable Projects

nrg NRG Energy successfully bid to acquire renewable energy projects around the country from bankrupt SunEdison for $144 million.

The sale, which needs to be approved in bankruptcy court, includes the 200-MW Buckthorn solar farm in West Texas. The project, slated for completion next year, would make the city of Georgetown the largest municipality in the nation powered solely by renewable sources. NRG already owns some wind projects in Texas; the deal would give the company its first solar plant in the state.

The deal could grow to $188 million if milestone benchmarks are met. It also includes solar and wind projects in Utah, Washington, California, Maine and Hawaii. Most of the projects remain in development and require additional investment.

More: Fuel Fix

AEP Seen Likely to Sell Remaining Ohio Coal Plants

American Electric Power, which just arranged a deal to sell four merchant generating stations in Ohio and Indiana, is still examining its options for four other coal-fired plants in Ohio with a capacity of 2,671 MW.

One option is to continue to push for reregulation in the Ohio legislature, which could prove to be a long and difficult fight. AEP would prefer to operate in a regulated environment in order to lock in rate certainty. But industry observers believe the more likely option is for AEP to put the plants up for sale.

“We think an outright sale of these assets in 2017 is the most likely outcome,” wrote analyst Andrew Bischof of Morningstar, which values the plants at $800 million.

More: Columbus Business First

Amazon Investing in Texas Wind Farm

Amazon is collaborating with Chicago’s Lincoln Clean Energy to build a 253-MW wind farm in Texas that will open by the end of next year. The Amazon Wind Farm Texas will include more than 100 wind turbines that will power Amazon facilities, including its cloud data centers.

Lincoln will build and own the wind farm, but Amazon is contracting to buy 90% of the generated power. “Amazon Wind Farm Texas is our largest renewable energy project to date and the newest milestone in our long-term sustainability efforts across the company,” Kara Hurst, Amazon’s director of sustainability, said last week.

The wind farm is Amazon’s most recent expansion into the Lone Star State. The online shopping giant opened a new “Silicon Hills” corporate hub last year in Austin and, in 2014, leased out office space at the Dallas Galleria complex. Amazon has two Dallas-area warehouses, or “fulfillment centers,” and a large warehouse and customer service center outside of San Antonio.

More: Houston Chronicle

Apache Works to Calm Fracking Fears Around New Texas Site

Apache Corp. executives are migrating to the town of Balmorhea, Texas, to assure the public that its recent oil and gas discovery in the Permian Basin won’t contaminate the San Solomon Springs. The nearby Balmorhea State Park is centered around a 3.5-million-gallon pool filled and fed by the springs, which keeps the park at a cool 72 to 76 degrees even in summer.

While Apache has leased the mineral rights under the state park, and under the town itself, the company promises not to drill on or under either. The company met with residents and officials in the region Friday to explain how it will keep the oil and water separated.

Apache announced the Permian Basin discovery this month. It said it expected to find more than 15 billion barrels of oil and gas under 350,000 acres near Fort Davis, Texas.

More: Houston Chronicle

GM Aims for 100% Renewable Use by 2050

General Motors says it has set a goal of increasing its renewable energy consumption from 3.8% currently to 100% of its needs by 2050. It plans to use wind, solar and landfill methane to attain its goal.

“Establishing a 100% renewable energy goal helps us better serve society by reducing environmental impact,” GM CEO Mary Barra said in a statement. “This pursuit of renewable energy benefits our customers and communities through cleaner air while strengthening our business through lower and more stable energy costs.”

The company is joining RE100, a group of 69 companies with the same goal. Other companies in the group include car companies Tata Motors of India and Germany’s BMW, as well as IKEA, Google and Hewlett Packard.

More: The Detroit News

GE Gets $1.9B Hinkley Contract

General Electric said it will make $1.9 billion on its contract to provide steam turbines, generators and associated equipment for the Hinkley Point C nuclear plant in England.

The plant, approved by the British government last week, is the first nuclear project in the U.K. in decades. GE, which bought the French company Alstom last year, has already been doing engineering work in preparation for the approval. Alstom won the original contract with project owner EDF several years ago.

The contract calls for two 1,770-MW steam turbines and generators and associated equipment. The project is expected to cost $24 billion in total.

More: Reuters

September 19, 2016

Analysis Recommends Continuing Reduced Con Ed-PSEG ‘Wheel’ for Grid Stability

By Rory D. Sweeney

VALLEY FORGE, Pa. — A power-flow analysis indicates a reduced version of the current flow pattern is the most reliable resolution when the Con Ed-PSEG ‘wheel’ ends on April 30, PJM and NYISO officials said last week.

The grid operators are recommending an “operational base flow” that continues to route 400 MW from upstate New York to New York City through northern New Jersey, a reduction from the 1,000 MW in the current wheel.

Consolidated Edison decided not to renew the wheel arrangement — which it used to move power from upstate New York through Public Service Electric and Gas facilities in northern New Jersey to serve its load in New York City — in a transmission cost allocation dispute. (See PJM, NYISO Seek Input on Replacing Con Ed-PSEG ‘Wheel’.)

To ensure operational flexibility during emergencies, the analysis used three “extreme” cases that focused on high load and high interchange and included 16 scenarios for various interchange distribution options, PJM’s Phil D’Antonio told the Operating Committee last week. It assumed 2,500 MW in exports to NYISO and 1,500 MW in imports to PJM, which are the historical maximums, he said. The analysis applied various percentage distributions of AC interchange on the eastern interfaces (5018, JK and ABC) to determine impacts, feasibility and operational flexibility.

The eight phase-angle regulators (PARs) involved in the analysis were fixed in their pre-existing positions during an initial analysis to determine the percentage of AC interchange that flows over the eastern interfaces. “We didn’t adjust any PARS in the analysis,” D’Antonio said. “We adjusted generation to determine what the flows were.”

Limitations

The analysis identified limitations both in delivering from NYISO to PJM on three lines (A, B and C) between New York City and northern New Jersey, and from PJM to NYISO on two lines (J and K) between Waldwick in northern New Jersey and Ramapo in upstate New York — a reverse of the existing wheel flows. Limitations included exhausted PAR taps, congestion in northern New Jersey and forcing flow from a 230-kV system at Waldwick to a 345-kV system at Ramapo. That system difference seems to be “the most limiting” factor from PJM’s perspective, D’Antonio said. NYISO also found delivery issues on the A, B and C lines using an N-1-1 analysis, he said.

PJM is considering a combination solution that first accounts for the operational base flow and then applies a percentage of the remaining interchange distribution. The J and K lines would shoulder 15%, while A, B and C would receive 21%. Line 5018, a 500-kV span between Ramapo and Branchburg in central New Jersey would receive 32%, and the remaining 32% would continue to flow on several western ties that cross the Pennsylvania-New York border as currently happens.

pjm, nyiso, con ed-pseg wheel — A “reduced” Con Ed-PSEG wheel

The flows would remain largely the same, but at reduced levels. A study of that option set an operational base flow bandwidth on the J/K and A/B/C lines between 300 MW and 500 MW. That option allowed the grid operators to meet their target flows and adhere to protocols, D’Antonio said.

No Surprise

“I don’t think that should come as a surprise to anybody [that] for 30-plus years we’ve been upgrading the Public Service North system with respect to the nonconforming wheeling service, so physically that’s naturally what the system would want to do outside of trying to force flows using the PARs,” D’Antonio said.

From a market perspective, maintaining a full -1000/1000 operational base flow creates the least additional congestion costs at 1.16%. The -400/400 option creates about 50% more at 1.8%, while the strict 0/0 creates the most at 2.14%. All three options are comparable in the productions costs and load payments they create.

Dave Pratzon of GT Power Group asked if NYISO is planning to reinforce its side of the system to better balance the flows now that Con Ed will no longer pay to maintain the wheel.

Several stakeholders have voiced concerns that the proposed solution provides benefits to Con Ed similar to the existing situation but absolves the utility from any responsibility for transmission upgrades. “A lot of people see … New York continuing to lean on PJM’s transmission system,” Pratzon said.

At a joint PJM/NYISO meeting Friday, NYISO reiterated its position that the proposed solution officially canceled the wheel, even if the flows continue.

NYISO will seek stakeholder approval for the joint operating agreement changes before a planned FERC filing in November. The RTOs are targeting the first quarter of 2017 for training and implementation of the new protocols.

─ William Opalka contributed to this report.

September 19, 2016

MISO Markets Committee of the Board of Directors Briefs

ST. PAUL, Minn. — Independent Market Monitor David Patton said that although MISO markets and operations performed well over a warmer-than-usual summer, there is room for improvement, namely in price-setting protocols.

Patton said MISO’s all-in energy price increased 9% from spring to summer, owing to increased gas prices and load. Summer load peaked at 121 GW on July 21, when a maximum generation alert was called, Patton said during a quarterly report at the Sept. 13 Markets Committee of the Board of Directors meeting.

“On several of these days, we committed a large amount of peaking resources,” Patton said. The Monitor said he was concerned that although July 21 was the hottest day of the year, prices weren’t the highest because utilities self-curtailed and demand response resources were not called on during the emergency maximum generation event. Real-time energy prices peaked at $36/MWh while the day-ahead price hit $78/MWh.

The voluntary curtailments led to a spike in revenue sufficiency guarantee (RSG) payments. Patton also said MISO committed more resources than necessary on some days because of incorrect load forecasting, leading to a “significant” uptick in RSG costs.

Todd Ramey, MISO vice president for system operations and market services, said July 21’s maximum generation event was the RTO’s first since the 2014 polar vortex and the first such event during summer in four years.

Patton also said only a few peaking resources were allowed to set prices on July 21. He said his proposal to expand the amount of resources able to set prices in extended LMP would alleviate dips in pricing during maximum generation alerts. Patton said if his ELMP recommendations were adopted, July 21’s average real-time system marginal price would have been 31% higher and real-time RSG would have been 14% lower.

MISO has said its simulations don’t support Patton’s proposal, which he first made in June’s State of the Market Report. (See MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing.)

Patton also said voluntary load curtailment is “somewhat troubling” because it is not integrated well into MISO’s market and distorts pricing.

“As far as control goes, there’s very little control with voluntary curtailment,” Patton said.

Patton recommended increasing the visibility of load curtailment and categorizing it as DR. He also said MISO could better integrate load curtailment into market products.

“You’re simply raising your hand and saying please curtail?” Director Paul Feldman asked MISO management.

“How much of [the event] was operational versus how much of it was procedural? Are there things we could do from a market perspective?” asked Director Baljit Dail.

“The prices ought to go through the roof in emergency situations,” Feldman added.

Richard Doying, executive vice president of operations and corporate services, said MISO was planning to present alternatives to the Monitor’s ELMP suggestion soon.

“I think it’s good that we have the point of view from Dr. Patton, but we’ll also get the alternatives from a practical point of view,” Director Phyllis Currie said.

Additionally, Patton said the summer was characterized by high congestion in MISO South early and high congestion in MISO North throughout August.

Director Michael Curran asked if market products were keeping pace with emerging issues. “It struck me that there are so many operational and procedural issues. It seems that the market is becoming operationally challenged, and I wonder if we have the tools,” he wondered.

Patton said the results weren’t gloomy, although MISO did experience one operating reserve shortage and local emergency conditions on several days. He said MISO was able to operate at 3% above its planning reserve margin requirement and there were no significant operating reserve shortages. He also said the market performed competitively and reliably and mitigation needs were “infrequent.”

“We’re going to be in emergency conditions much more often,” MISO CEO John Bear said. “Does that mean we’re right at the edge? No.”

Currie asked if MISO had learned any lessons in communicating with balancing authorities over the summer in light of the higher loads. “I think that the current communication protocols are sufficient today,” Ramey said.

Ramey reported that the average summer day-ahead energy price was $29.55/MWh, 3.7% higher than summer 2015, propelled by a 3% increase in load. However, summer saw a 7.5% decrease in natural gas prices compared to summer 2015, averaging $2.60/MMBtu. Wind power production grew 18% from last summer, while installed wind capacity increased by 9%. Planned generation outages averaged 6.3 GW, up 10.7% when compared to last summer, and forced generation outages averaged 14.5 GW, up 6%.

MISO Attorneys Address Board Role in Capacity Auction Conflict

With the capacity auction redesign debate as a backdrop, three attorneys were on hand to clarify the board’s role when MISO’s management, stakeholders and Monitor can’t agree. (See MISO Sees Nov. 1 Filing on Forward Auction; Simulation Shows Price Disparities.)

MISO Senior Vice President of Compliance Services Stephen Kozey said no one should govern the board’s actions, but the board should “certainly” listen to all sides.

Counsel to the board Karl Zobrist said that while the board doesn’t make design changes, it can review proposals and provide or withhold endorsement. Zobrist also said the Monitor can make recommendations and intervene in FERC filings, but the board is under no obligation to advocate the Monitor’s recommendations.

“It’s important that there be a robust dialogue,” MISO General Counsel Andre Porter added.

“We need to make sure we’re listening not only to the IMM but the Advisory Committee and the stakeholders,” Dail said. “But I don’t think we should be saying, ‘This is how market design should work.’”

Zobrist said the board should not blindly defer to management. “You have the duty of care and duty of loyalty … and if you’re confident management is making a good decision, you should support it,” he said.

— Amanda Durish Cook

September 19, 2016

PJM Market Implementation Committee Briefs

Continue reading “PJM Market Implementation Committee Briefs”

September 19, 2016

CAISO Issues Revised Proposal to Expand LSE Definition

By Robert Mullin

CAISO last week released a final draft proposal to expand the definition of a “load-serving entity” to include organizations purchasing wholesale power to serve their own needs.

The ISO’s latest draft seeks to address market participants’ concerns that the wording of the initial proposal could subject them to unwanted obligations. (See CAISO Proposes Broadening LSE Definition.)

CAISO’s Tariff currently recognizes LSEs as only those entities that sell electricity or serve load to end users, a description that covers utilities, federal power marketing agencies and community choice aggregators. A special provision is made for the State Water Project (SWP), a California agency that directly engages the wholesale market to cover its own energy requirements.

The ISO seeks to broaden the definition to accommodate the San Francisco Bay Area Rapid Transit District (BART), which, like the SWP, serves its own load but does not meet the standard definition of an LSE. BART’s transmission contract rights on Pacific Gas and Electric’s network — which predate the existence of the ISO — are set to expire at the end of the year. Those rights will automatically convert to CAISO service, leaving the agency exposed to congestion charges.

caiso, load-serving entity — CAISO is seeking to expand the definition of an LSE to accommodate the Bay Area Rapid Transit District, which serves its own load and will soon be subject to congestion charges. *Photo source: BART*

A recognized LSE facing a similar circumstance can cover that exposure by seeking a free allocation of congestion revenue rights (CRRs) in the initial round of CAISO’s annual allocation process. In that case, the ISO would treat the expiring contract rights as if they were expiring annual CRRs.

Under current practice, BART is unable to seek that remedy because it does not meet the Tariff definition of an LSE.

For LSEs, the CRR benefit comes with a corresponding obligation: the need to procure enough resources to support their loads plus a reserve margin — the “resource adequacy” provision.

That requirement prompted unease for at least one ISO stakeholder — the Metropolitan Water District of Southern California. While the district is authorized to serve its own load, it currently relies on Southern California Edison to meet its energy needs under a long-term agreement.

During an Aug. 23 call to discuss the proposed definition change, a representative from the water district said his agency was concerned that it would face a resource adequacy obligation upon expiration of its transmission contract rights on SoCalEd’s system.

The latest draft attempts to address that concern by adjusting the language of the revised definition.

“The ISO clarified that an entity must be an end user, have the authority to serve its load through the wholesale purchase of power and choose to exercise its authority to serve its load through the wholesale purchase of power,” CAISO said.

The updated proposal addresses additional issues raised by market participants, including:

Clarifying that the proposed definition applies only to entities serving their own load through the purchase of energy, and not to those generating power on site for their own use;
Describing the CRR allocation impact under multiple scenarios related to entities with or without existing transmission contracts and ownership rights to demonstrate that there will be little or no impact to current CRR allocation participants; and
Removing the term “California” from the definition to include entities such as Nevada-based Valley Electric Association, an existing ISO member.

CAISO has scheduled a Sept. 21 call to discuss the proposal and plans to submit a final amendment for approval to the Board of Governors in late October.

September 19, 2016

MISO 5-Year Plan Seeks New Products, Workforce Improvements

By Amanda Durish Cook

ST. PAUL, Minn. — MISO released a five-year operations business plan last week that calls for new products, technology upgrades and a better-trained workforce.

The Board of Directors reviewed the plan at its Markets Committee meeting last week.

The plan includes “investment in forward-looking, strategic products to respond to tightening reserve margins, increasing reliance on renewables and need for increased gas-electric coordination.”

“Looking forward, the confluence of technology, market, policy, regulatory and other external drivers will accelerate the pace of change,” MISO said. “To continue to deliver and to extend [MISO’s] value proposition, we must invest in our markets, organization and technology.”

It also calls for developing existing staff and “modifying hiring criteria” to improve the organization’s strategic and commercial skills while also streamlining current processes and incorporating more automation.

MISO said the plan would cost $13 million and yield $30 million in benefits next year. The RTO expects the entire plan to cost $51 million in operating and capital expenses and deliver annual benefits of more than $100 million through 2021.

“I’m not accustomed to seeing [returns on investment] in the thousands percent, so … it makes me somewhat skeptical. We’re going to need some more information,” Director Thomas Rainwater said.

Jeff Bladen, MISO’s executive director of market design, said the annual benefits assume that the RTO can allocate the research costs and that the technology is in place in time. He said MISO would make more presentations on the plan.

“This assumes that we have the people and technology in place that allow us more flexibility,” Bladen said.

The plan includes MISO’s introduction of a separate forward capacity auction for competitive areas next year, followed by seasonal and locational capacity market changes in 2018.

The plan also sets the following goals for 2018-21:

Replacing the 2004 “freeze date” reference point in MISO’s flowgate allocation process by 2018;
Allocating feasible auction revenue rights and nominating infeasible long-term transmission rights in 2019;
A multiday financial commitments market, a multiyear financial transmission rights auction and a short-term capacity reserve market by 2020; and
A special pricing structure for voltage and local reliability (VLR) commitments and a virtual spread market product by 2021.

Among the benefits cited by MISO are a reduced likelihood of outages; more capacity availability; improved reliability; improved congestion hedging; reduced production costs; and more efficient real-time interchange and better price convergence with its neighbors.

Independent Market Monitor David Patton said it would be helpful if MISO designed more flexible software so entirely new code isn’t needed every time the RTO makes a market change.

September 19, 2016

Natural Gas, Offshore Wind, Storage Seek Their Places in NY’s Future

By Rich Heidorn Jr.

SARATOGA SPRINGS, N.Y. — The last panel of the Independent Power Producers of New York’s fall conference last week featured an environmental activist and representatives of the energy storage, wind and solar industries.

And then there was Karen Moreau, charged with making the case for the long-term future of natural gas. She decided to try humor.

renewable power, new york — Moreau © *RTO Insider*

“If natural gas was on an online dating site … the profile would be ‘clean, reliable, affordable and flexible,’” said Moreau, executive director for the American Petroleum Institute in New York. “I don’t know how many people would take a look, at least not at first. They’d probably go to some of the other, more attractive, sexy forms of energy like wind and solar.

“But then again, online dating does involve a certain element of hope and fantasy, and so let’s talk about statistics,” she continued.

And the statistics, she said, indicate gas will be needed for the foreseeable future to help balance intermittent renewables.

Reserve Margins and Ancillary Services

Moreau quoted a 2016 National Bureau of Economic Research study that concluded a 1% increase in fast-reacting fossil fuel generating capacity was needed to support a 0.88% increase in renewable capacity. She also cited NYISO’s controversial prediction that full implementation of the state Clean Energy Standard will require increasing the installed reserve margin to at least 40% from the current 17.5%.

And renewables are not well suited to provide ancillary services such as voltage support, regulation and frequency control, operating reserves and black start, currently provided by gas-fired generation, she said.

Anne Reynolds, executive director of the Alliance for Clean Energy New York, agreed that gas will have a role. Jackson Morris, Eastern energy director for the Natural Resources Defense Council, said that role could persist even through midcentury under the state’s plan to reduce greenhouse gas emissions by 80% by 2050.

Stranded Assets?

But Morris said policymakers must beware of overinvesting in gas infrastructure that could become stranded assets.

“What’s going to happen is if we’re not careful — if we’re building out 40- to 50-year infrastructure, whether its pipelines or combined cycle plants — we could easily be either running into a brick wall and not meeting the necessary climate trajectory we need to be on, or alternatively … you could end up with a ton of sunk costs.

“If you don’t have that time horizon right, if you don’t build out a regulatory framework that has the right foresight, you could literally be on a path that looks really promising and run square into a giant brick wall when you get to 2030.”

Need for Storage

Moreau acknowledged that gas’s future is tied to the cost curve for energy storage. If storage gets cheap enough, it could compete particularly with simple cycle gas peaking plants, some say.

new york renewable power — The panel (left to right): Morris, Reynolds, Moreau and Sheehan © *RTO Insider*

New York’s climate goals also will require as much as 4 GW of energy storage by 2030, said Denise Sheehan, senior advisor to the New York Battery and Energy Storage Technology Consortium. The group is proposing a “no regrets” target of 1 GW of multihour storage by 2022 and 2 GW by 2025.

“These projects are happening. They’re real,” she said.

Offshore Wind Essential to 2030 Target

While conceding a continuing need for gas, Morris and Reynolds were far more bullish on the role offshore wind will play in New York’s future.

“You cannot get to 50% [renewables] by 2030 without offshore wind. Period,” Morris said. “If we lay the groundwork right now [for] 2030, could we have potentially thousands of megawatts of over 50%-capacity-factor, carbon-free resources located close to the highest load pockets in the state? We absolutely could. There’s no question.”

Levelized costs for offshore wind in Europe have dropped 50% in the last seven years, with recent projects coming in below 8.5 cents/kWh, Morris said. A June 2016 paper by the National Renewable Energy Laboratory and Lawrence Berkeley National Laboratory forecast that offshore wind costs will drop as much as 30% more by 2030.

But that assumes a pipeline of projects, according to Reynolds, who said that “critical mass” could be reached by developments in New York, Massachusetts, New Jersey and Maryland.

Offshore wind, common in Europe, has been slow to gain a foothold in the U.S. The Cape Wind project in Massachusetts, which advertised itself as the first offshore project in the U.S., has stalled following years of litigation, local opposition and legislative battles.

But the potential — particularly in the shallow waters of the Atlantic coast — is compelling and advances have begun occurring at a faster pace.

The U.S. Bureau of Ocean Energy Management has awarded 11 commercial offshore wind leases, including two sites each off New Jersey, Maryland and Massachusetts, one off Virginia and two off the Rhode Island-Massachusetts border.

In June, BOEM identified New York’s first “wind energy area,” 12 miles off Long Island. BOEM is expected to auction off development rights in December.

Construction of the nation’s first offshore commercial wind farm, off Block Island, R.I., was completed in August and is expected to begin operations by the end of 2016.

Earlier this month, the U.S. departments of Energy and the Interior released their second National Offshore Wind Strategy.

On Sept. 12, Reynolds’ group, which represents wind and solar developers, announced a spinoff organization, the New York Offshore Wind Alliance.

And on Thursday, New York Gov. Andrew Cuomo and the New York State Energy Research and Development Authority released an offshore wind blueprint outlining the state’s plan to identify the most promising wind development sites within a 16,740-square-mile area.

Meanwhile, the Long Island Power Authority could vote as soon as Wednesday to authorize a 90-MW offshore project 30 miles northeast of Montauk.

Morris said he was undaunted by the fate of Cape Wind. “You had technology in a different place. You had public policy in a different place,” he said. “We’ve learned a lot from Cape Wind.”

Other IPPNY Fall Conference Coverage