VIDEO: ISO New England capacity market grows in participation

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Participation in the forward capacity market by demand side resources, including energy efficiency measures and active demand response resources, increased 19 percent from 1,535 MW in December 2013, to 1,821 MW last December, ISO New England (ISO-NE) said on May 20, discussing key findings of the “2014 Annual Markets Report.”

Wholesale power markets in New England operated competitively last year, with prices that reflected the cost of production, according to the report issued by ISO-NE’s Internal Market Monitor, ISO-NE said.

The average real-time price of wholesale electric power in 2014 rose about 13 percent, to $63.32 per MWh, largely driven by higher fuel costs in the first quarter when extreme cold weather increased demand for natural gas, which generates nearly half of the electricity produced in the region, ISO-NE said, adding that the resulting spike in gas prices caused wholesale power prices to rise.

ISO-NE said that other key findings of the report include:

·      The total value of the region’s wholesale electricity markets, including electric energy, capacity and ancillary services markets, rose about 12 percent, from about $8.8 billion in 2013, to about $9.9 billion in 2014, with electric energy comprising $8.4 billion of the total in 2014

·      At 127,138 GWh, total electricity usage in the region was 2 percent lower in 2014 than in 2013

·      Resources can receive payments, in addition to energy market revenues, to cover their costs if they are needed to help ensure the reliability of New England’s power system. Those additional payments increased 10 percent to $173.7 million in 2014; about 62 percent of the payments stemmed from the need to operate more expensive generation during extreme cold weather in 1Q14

·      The cost of capacity in 2014, resulting primarily from the third and fourth FCM auctions held in 2009 and 2010, respectively, rose by 1 percent to $1.06 billion. The report noted that the first seven auctions cleared with excess capacity but the eighth auction, conducted in February 2014 for the 2017-2018 capacity commitment period, concluded with a slight shortfall after 3,135 MW of existing resources announced plans to retire in 2017. The retirements triggered administrative pricing rules designed to protect consumers from higher capacity prices while still providing incentives for developers to build and retain resources

On demand response, the report noted that in 2010, demand resources were integrated into the FCM where they offer in the forward capacity auctions, take on capacity supply obligations and receive capacity payments comparable to other supply side resources.

The two broad categories of demand resources in the FCM are active and passive demand resources. Active demand resources, the report added, are dispatchable and reduce load in response to ISO dispatch instructions, while passive demand resources are not dispatchable and provide load reductions during predetermined periods.

In addition to real-time demand response resources, which reduce load within 30 minutes of receiving an ISO dispatch instruction, active demand resources include real-time emergency generation resources, which reduce load by transferring load that otherwise would be served from the electricity grid to emergency generators. Passive demand resources include on-peak resources, like energy efficiency projects and distributed generation that reduce load during predefined periods, and seasonal peak resources, like energy efficiency projects where the project’s load reduction is weather sensitive.

The report also said that in 2012, from Jan. 1 through May 31, ISO-NE administered two demand response programs that provided financial incentives for customers to reduce load in response to day-ahead and real-time energy prices: the Real-Time Price-Response (RTPR) Program and the Day-Ahead Load-Response Program (DALRP). An optional program, the Transitional Price-Responsive Demand (TPRD) Program, designed to comply with FERC Order 745, replaced the RTPR program and the DALRP, and is currently in effect.

Order 745 requires RTOs to pay the full locational marginal price (LMP) for load reductions produced by demand response resources participating in organized wholesale energy markets subject to certain conditions, the report added.

Similarly to the DALRP, the TPRD program allows market participants with assets registered as RTDR resources to offer load reductions in response to day-ahead LMPs.

Market participants are paid the day-ahead LMP for their cleared offers and must reduce load by the amount cleared day-ahead. The participant, the report added, is then charged or credited at the real-time LMP for any deviations in curtailment in real-time compared with the amount cleared day-ahead. The TPRD program will remain in effect until June 1, 2017, at which time new market rules will become effective that will fully integrate dispatchable demand resources into the day-ahead and real-time energy markets.

Discussing Order 745 further, the report noted that the order was challenged in 2012 in the U.S. Court of Appeals for the District of Columbia. In May 2014, the D.C. Circuit issued an opinion – by a 2-1 vote – vacating the order, stating that, for instance, FERC lacked jurisdiction to promulgate the rules established by Order 745. However, the report added, the D.C. Circuit also stayed the mandate to vacate Order 745 pending the outcome of any further appeal to the U.S. Supreme Court.

Last July, FERC asked the D.C. Circuit to rehear the case en banc – a request for rehearing before the full 11-member court. The court last September denied FERC’s request. In January, the report added, the U.S. Department of Justice, on behalf of FERC, petitioned the Supreme Court to review the D.C. Circuit’s decision and overturn its ruling.

As TransmissionHub reported, the Supreme Court on May 4 granted a petition for a writ of certiorari filed on Jan. 15 by Department of Justice Solicitor General Donald Verrilli, on behalf of FERC, for review of the judgment of the U.S. Court of Appeals for the District of Columbia in FERC v. Electric Power Supply Association (EPSA).

The petition asked the Supreme Court to consider whether FERC reasonably concluded that it has authority under the Federal Power Act (FPA) to regulate the rules used by operators of wholesale electricity markets to pay for reductions in electricity consumption, known as demand response, and to recoup those payments through adjustments to wholesale rates.

Based on its interpretation of FPA Sections 824(d) and 824(e), FERC in 2011 issued Order 745 to eliminate barriers to the use of demand response commitments in wholesale markets. The Court of Appeals on May 23, 2014, vacated Order 745 in FERC v. EPSA, finding that FERC’s interpretation of Sections 824(d) and 824(e) was overreaching and that states have exclusive authority to regulate the retail market.

In the arguments for granting the petition, Verrilli claimed that the Court of Appeals “seriously misinterpreted” the FPA, and that the Court of Appeals’ analysis was driven by a concern that FERC’s position would permit FERC to regulate the retail electricity market and other markets for generation in-puts, such as fuel and steel.

The report issued on May 20 said: “Until a final decision is reached on the D.C. Circuit’s vacatur of Order 745 the ISO’s demand response rules contained in the tariff will continue to apply. If vacatur ultimately stands, the D.C. Circuit Court’s ruling would be remanded to FERC for further action.”

Of demand resources in the FCM, the report noted that the total capacity supply obligations (CSOs) for all demand resources participating in the FCM increased by 19 percent in 2014, compared with 2013, a gain of 286 MW. The CSOs of passive demand resources accounted for the vast majority of the increase, 240 MW, or 84 percent. The increase in the CSOs over the year is mostly attributable to energy efficiency programs administered by local utilities.

The report also said that demand resource payments totaled $90.3 million in 2014, compared with $87.5 million in 2013, an increase of 3.2 percent.

Among other things, the report noted that two recommendations for demand response were made in the “2013 Annual Markets Report,” with one concerning demand response baselines and their predictive power – accuracy – in forecasting various resource load shapes, and the other addressing third-party verification of meter data submitted by market participants for their demand response resources.

The report noted that in 2014, ISO-NE researched various alternative baseline methodologies to improve the accuracy of estimated baselines in predicting actual load shapes. The work that the ISO did was submitted to an independent consulting firm, which is currently reviewing the proposed methodology that the ISO submitted, as well as possibly proposing recommendations for further improvements that may be discovered during the review process.

The report added that the planned implementation date for the new baseline methodology is currently June 1, 2017, at which time new market rules will become effective that will fully integrate dispatchable demand resources into the day-ahead and real-time markets.

“Given the uncertainty in FERC jurisdiction over demand-response participation in energy markets “, the ISO’s current plan to fully integrate demand response into the energy markets on June 1, 2017, including the implementation of any baseline changes, may need to be modified,” the report said.

If, and when, the new baseline methodology is implemented, the new methodology’s predictive ability in estimating a resource’s actual load should be made transparent to the market. The report further noted that the accuracy of the new baseline methodology should be made available to the market by whatever metrics ISO-NE believes would best describe how well the methodology is performing.

While any methodology will perform better for some demand response resource load profiles than others, a report reflecting the accuracy over the broad array of resources will give more confidence in the methodology and ultimately its ability to measure load reductions produced by demand response resources, the report said.

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