Posted on June 26, 2012 by Linda R. Evers

NERC's 2012 Summer Reliability Assessment Says Resources Generally Sufficient to Meet Summer Peak Demands Amidst Concerns with ERCOT and California

The North American Electric Reliability Corporation’s (NERC) 2012 Summer Reliability Assessment finds most of North America has sufficient resources available to meet summer peak demands, however, planning reserve margins in the Electric Reliability Council of Texas (ERCOT) assessment area are projected to be below the NERC Reference Margin Level, the threshold by which resource adequacy is measured. In California, reserves are projected to be tight but manageable through the summer months.

With continued growth in peak demand and only a small amount of new generation coming online, resource adequacy levels in ERCOT have fallen below targets,” said John Moura, manager of Reliability Assessment at NERC. “If ERCOT experiences stressed system conditions or record-breaking electricity demand due to extreme and prolonged high temperatures, system operators will most likely rely on demand response and emergency operating procedures, which may include initiating rotating outages to maintain the reliability of the interconnection.

Texas is no stranger to rotating outages. Shortly before Super Bowl XLV, brownouts occurred when extreme cold weather hit the Southwest the first week of February 2011. The Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation released a staff report making recommendations to help prevent a recurrence of rolling blackouts and natural gas curtailments. Hopefully the lessons learned can help this situation. 

Despite the concerns in Texas and California, according to Mark Lauby, vice president and director of Reliability Assessment and Performance Analysis, NERC has reviewed the operating procedures and preparations in the assessment areas, and in most areas they appear to be sufficient to meet these challenges. Since summer 2011, capacity resources have grown across North America by approximately 12,310 megawatts, most notably within the SERC Reliability Corporation and the Northeast Power Coordinating Council areas. Compared to the 2011 projections, NERC-wide total peak demand forecast is 3,700 MW lower. The largest increase in peak demand is expected in ERCOT, where a 1.7 percent increase is projected.

Posted on July 14, 2011 by Linda R. Evers

National Town Meeting on Demand Response and Smart Grid

The Association for Demand Response and Smart Grid ("ADS") hosted its 8th National Town Meeting July 12-14, 2011. In addition to sharing best practices and lessons learned, the meeting highlighted the extraordinary amount of work yet to be accomplished in order to provide US citizens with the full benefits of the smart grid. I found Senator Mark Udall's (D-CO) keynote address interesting and informative. "You grow by innovating, not by looking back," challenged Senator Udall. A belief that innovation is the key to our energy future is what lead the senator to co-sponsor a bipartisan bill with Senator Scott Brown (R-MA), the Electric Consumer Right to Know Act (S 1029), referred to as e-Know. The bill:

  • Provides customers the right to real-time access to their electric usage information
  • Allows customers to benefit directly from new information generated by the smart grid
  • Allows customers to provide third parties, such as companies that facilitate home energy management systems, with access to their usage data
  • Is technology-neutral, giving customers the right to choose how they receive their consumption data

The belief here is that information will encourage others to design and offer systems to customers that will assist with energy management. When asked, "How do you promote this to customers?" by an attendee, Senator Udall responded,

Green is the new Red, White and Blue. It is complementary and protective of our freedom.

Data access was not the only concern raised. FERC Chairman Jon Wellinghoff addressed demand response compensation. "The market needs to be structured so that demand response gets the compensation it deserves," he stated. To highlight the value of DR, the chairman used a PJM example. In August 2006, PJM reported its largest peak load. Demand response saved over $200 million dollars. With savings like this, DR cannot be ignored. Hopefully MISO representatives were in the room because Chairman Wellinghoff had a heads up for them: Make sure your soon-to-be-filed capacity market plan includes demand response!

Full of information touching every aspect of DR and the Smart Grid, the National Town Meeting was worth my train ride from Philly to DC. For example, I learned from Diane Regas, Associate VP, Programs, at the Environmental Defense Fund, that the organization released a fact sheet addressing the radio frequency ("RF") concerns raised by some smart meter customers. Hopefully it will assuage their fears. Industry players involved on the international level like Seimens, Silver Springs Network and Enbala agreed that entities in other countries look to the US for insight in these matters. And Eric Dresselhuys, Executive Vice President, Silver Springs Networks touched on the smart meter battle occurring across the US: "$0 - $1.00 per customer is the range that is killing projects." Wow! As someone who handles rate cases, I know the battle is often over cents. But hearing Eric say it, really made me wonder: How could we compromise our energy future over cents? Given the importance of energy to our economy, why would we not select the option providing the stronger energy future instead of a mid-term fix? In spite of leaving the meeting inspired and concerned,  I plan on attending for the entire three days next year.

Posted on March 23, 2011 by Linda R. Evers

FERC says Negawatt = Megawatt

Last week, FERC issued a final rule amending regulations under the Federal Power Act regarding Demand Response Compensation in Organized Wholesale Energy Markets, putting an end to industry speculation over the value of demand response…hopefully. Regional Transmission Organizations (“RTO”) and Independent System Operators (“ISO”) must balance generation and load when clearing the day-ahead and real-time energy markets. Balancing can be accomplished by changes in supply or demand. The Commission found that in the organized wholesale energy market, demand response has the same balancing effect on supply and demand as generation. Therefore, demand response resources should be compensated on an equal basis to generation resources. However, two conditions must be met:

  1. The demand response resource has the capability to provide the service, i.e., the demand response resource must be able to displace a generation resource in a manner that serves the RTO or ISO in balancing supply and demand.
  2. The payment of LMP for the provision of the service by the demand response resource must be cost-effective as determined by the net benefits test.

What is the net benefits test? When is a demand response cost-effective? We will have to wait a little longer to completely answer these questions. RTOs/ISOs are ordered to conduct two studies: By July 22, 2011, RTOs/ISOs must submit an historical analysis of supply curves and revised tariffs. More than a year later by September 21, 2012, a dynamic benefits study must be filed. While time may not be a friend, EnerNOC is having an awesome month at FERC!

Posted on March 09, 2011 by Linda R. Evers

EnerNOC wins Declaratory Judgment in PJM Battle

On February 22, 2011, demand side management (“DSM”) company EnerNOC, filed a Petition for Declaratory Order requesting that FERC find that EnerNOC and other companies may continue to register customers and settle under PJM’s GLD baseline methodology as they have in previous periods without enforcement action being threatened. GLD is one of three baseline methods prescribed in the PJM business rules for measuring event compliance. GLD is achieved by a customer reducing its load by a predetermined amount (i.e., by the Guaranteed Load Drop or GLD). PJM Tariff, Attachment DD, section H.

EnerNOC’s filing was in response to a joint statement issued by PJM and Monitoring Analytics, LLC, PJM’s Independent Market Monitor (“IMM”), that addresses a double counting issue. The Joint Statement says in part:

The following example illustrates the issue:

  1.  5,000 kW PLC (10/11 Delivery Year) – PLC represents how much capacity has been purchased for customer to ensure reliability. Since the customer actively reduces load during the peaks (“peakshaver”) the PLC is significantly lower than normal amount of load for the customer, which is 28,000 kW.
  2. 4,000 kW Nominated Installed Capacity – CSP commitment for quantity of customer load reduction when PJM needs during an emergency. The nominated amount may not exceed the PLC based on current market rules.
  3. Real time estimated load reduction = 25,000 kW measured as the difference between a baseline estimate based on recent days, 28,000 kW, less actual consumption during the event, or 3,000 kW.
  4. 21,000 kW over compliance – CSP resource will be deemed to have met nominated Installed Capacity commitment of 4,000 kW AND also receive an additional 21,000 kW of over compliance credit which may be used to offset resources within the zone than did not perform.

In addition to substantially overstating the demand side savings and overpaying CSPs, this behavior also provides a non-competitive advantage to CSPs in attracting customers. A CSP that is aware of this Program discrepancy may identify large customers with managed PLCs and offer such customers out of market revenues for any load reduction in excess of the nominated amount. This is profitable because once such a customer has been procured, the CSP has the ability to sign up customers in the same zone with no or only limited ability to reduce load when called upon and receive capacity revenues based on the apparent over compliance of the customers with managed PLCs.

In its Order, FERC states that the Commission does not intend to institute any enforcement actions against EnerNOC (or other similarly situated ARCs) for registering customers in good faith and settling under the GLD baseline methodology. Good faith participation in the PJM load management programs, including accurate customer GLD registration and aggregation during emergency events, is permitted. The Commission goes on to warn that this finding here does not exempt from challenge conduct prohibited under section 1c.2 of the Commission’s regulations. 18 C.F.R. § 1c.2 (2010).