News + Events
Washington Energy Report - (1) FERC Exempts Small Utilities from Demand Response Rule (2) FERC Finds No Market Manipulation in Lake Erie Loop Flow Problem (3) FERC Rejects PJM's Method of Assessing Seldom-Run Resources (4) WAPA May Join LS Power as Partner to 500 kV Idaho-Nevada Line
Washington Energy Report
July 24, 2009
FERC Exempts Small Utilities from Demand Response Rule
On July 16, 2009, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order No. 719-A affirming its decision in Order No. 719 that removing barriers to demand response is consistent with FERC’s duty to ensure the sound operation of organized wholesale electric markets. However, FERC exempted small utilities that distributed up to 4 million megawatt-hours (“MWh”) during the previous year.
The Commission issued Order No. 719 on October 17, 2008, to improve the operation of organized wholesale electric markets in four areas: (1) demand response, including pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”) to their customers and other stakeholders.
Order No. 719 required grid operators to accept bids from demand resources and to waive charges to energy buyers for voluntarily reducing demand during an emergency. It also required RTOs and ISOs to amend their market rules as necessary to permit an aggregator of retail customers to bid demand response on behalf of retail customers directly into the RTO’s or ISO’s organized markets, unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate.
In Order No. 719-A, the Commission modified the rule to prohibit market operators from accepting bids that include aggregated demand response provided by customers of small utilities that distributed up to 4 million MWh during the previous year, unless a small utility’s retail regulator authorizes such aggregation. RTOs and ISOs may continue to accept bids from companies that aggregate demand response provided by customers of larger utilities, unless the relevant retail regulator prohibits those customers from participating in wholesale markets.
The Commission reiterated that existing RTO and ISO market rules that do not allow for prices to rise sufficiently during an operating reserve shortage to allow supply to meet demand may be unduly discriminatory. Therefore, the Commission reaffirmed its decision to require RTOs and ISOs to reform their market rules so that prices during operating reserve shortages more accurately reflect the value of energy during such shortages. The Commission stated that this shortage pricing rule is intended to correct this issue while providing protection against the exercise of market power.
Order No 719-A also expands and clarifies the role of market monitors. The modified rule allows an independent market monitor to oversee both the RTO or ISO as well as market participants operating in the same RTO or ISO for activity in that RTO or ISO. To alleviate concerns over potential conflicts of interest, the Commission will permit an RTO or ISO market monitor to enter into contracts to monitor a market participant operating in the same RTO or ISO for activity in that RTO or ISO, under the following conditions: (1) the relationship between the entity and the market monitor and the market monitor’s scope of work for the entity are both mandated by the Commission in an order on the merits, (2) the contract is filed with the Commission for approval, and (3) the contract contains a provision that the entity must obtain permission from the Commission to terminate the employment of the market monitor.
The Commission’s order is available at: http://www.ferc.gov/whats-new/comm-meet/2009/071609/E-1.pdf.
FERC Finds No Market Manipulation in Lake Erie Loop Flow Problem
On July 16, 2009, the Commission adopted staff’s conclusion that there were no deceptive or fraudulent actions taken by market participants when they placed circuitous power delivery schedules around the Lake Erie region in 2008. While the Commission did not find any market manipulation that directly led to the Lake Erie “loop flow” issues, it did order market operators in New York and surrounding regions to find long-term, comprehensive solutions to the problem and submit those solutions to the Commission within six months.
Beginning in spring 2008, speculation grew that market participants were increasing their transactions over indirect paths around Lake Erie in order to take advantage of the different pricing policies of the four RTOs surrounding the lake. The transactions were scheduled to exit the New York Independent System Operator, Inc.’s (“NYISO”) transmission paths, flow through the Electricity System Operator of Ontario, into the Midwest Independent Transmission System Operator, Inc. (“MISO”), and eventually end up in the territory of PJM Interconnection, L.L.C. (“PJM”).
Despite the scheduled paths, NYISO claimed that nearly 80 percent of the power simply flowed over NYISO and PJM’s common border. The resulting discrepancies between scheduled and actual flow paths increased congestion and uplift costs while causing market distortions. As a result, the Commission’s Office of Enforcement initiated a non-public investigation into the suspicious power flows in May 2008. The Commission also accepted NYISO’s interim tariff revisions to terminate scheduling on the paths under investigation (see November 14, 2008 edition of the WER).
The Office of Enforcement’s investigation concluded that the market participants were simply responding to price signals when they placed their circuitous power delivery schedules. The participants had not previously been warned to avoid the creation of the loop flow or told that clockwise loop flow would result from their schedules. Additionally, loop flow historically had been predominately counterclockwise and had harmed PJM and MISO but benefited NYISO by decreasing its congestion. The Office of Enforcement went on to find that these actions were not used to artificially affect market signals or increase congestion or prices. As a result, the market participants did not engage in any market manipulation or violate any tariff provisions.
While the Commission accepted the Office of Enforcement’s conclusion and ruled that no market manipulation had taken place, it still noted the persistent problems caused by the Lake Erie loop flow. The Commission asked NYISO and neighboring RTOs to develop long-term solutions to these issues expeditiously and collaboratively while focusing on interface pricing and congestion management. A copy of the Commission’s order is available at: http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12083287.
FERC Rejects PJM's Method of Assessing Seldom-Run Resources
On July 16, 2009, FERC granted a complaint filed by Pepco Energy Services, Inc. (“Pepco”) challenging provisions of PJM’s Open Access Transmission Tariff regarding peak-hour-period availability penalties for infrequently-run generation units. The Commission determined that the market rules governing the peak-hour-period availability penalties for infrequently-run generators were unjust and unreasonable, and established new rates to be applied as of the date of the complaint (April 22, 2008).
In PJM’s capacity market, resources that commit to provide capacity when dispatched by PJM are paid a rate determined by a capacity auction. The peak-hour availability charges and credits provide a means to assess whether generation resources committed as capacity actually are available at expected levels during peak periods. The charges are calculated by comparing actual availability during peak hour periods with expected availability. For any unit that has at least 50 service hours during peak-hour-period, a unit’s actual availability is determined by assessing its availability during the 500 peak hours of the delivery year. The charges and credits for infrequently-run units with fewer than 50 total service hours during peak periods are based on their forced outage rate for all 8,700 hours in the delivery year. Pepco alleged that under this calculation method, seldom-run units can incur substantial peak-period availability charges because of their unavailability during non-peak hours in the delivery year.
Pepco proposed separate remedies in three distinct time periods. For the 2007-2008 delivery year (which was to end on May 31, 2008), Pepco requested that the Commission find that generation resources with fewer than 50 service hours during peak hours in a delivery year should not be subject to charges and credits assessed under the peak-hour-performance market rules. For the 2008-2009 delivery year, which was to start on June 1, 2008, Pepco requested that the Commission require PJM to delete the special rules applicable to infrequently-run generation resources, and adopt the same metric for all generation resources. For the 2009-2010 delivery year and beyond, Pepco requested the Commission to direct PJM, to explore through its stakeholder process alternative methods for assessing peak-hour-period availability charges on infrequently-run generation resources, and to make a Federal Power Act (“FPA”) section 205 filing proposing a replacement methodology.
The Commission had held the complaint in abeyance while PJM stakeholders considered possible changes to the market rules governing the peak-hour-period availability metrics for infrequently-run generators. As a result of that process, PJM filed changes, in Docket No. ER09-412-000, to the peak-hour-availability provisions pursuant to section 205 of the FPA. These changes provide that the peak-hour-availability measure of an infrequently-run resource shall be the lower of the resource’s peak-period or yearly metric.
FERC found that this remedy addressed the issue going forward. The Commission stated that because the 2007-2008 period preceded the filing of the complaint, no relief could be granted. Consistent with that approach, the Commission determined that because the complaint was filed before the 2008-2009 delivery year, PJM and other parties were on notice and refunds, if necessary, were justified.
The Commission’s order is available at: http://www.ferc.gov/whats-new/comm-meet/2009/071609/E-29.pdf.
WAPA May Join LS Power as Partner to 500 kV Idaho-Nevada Line
On July 16, 2009, the Western Area Power Administration (“WAPA”) and an LS Power affiliate, Great Basin Transmission LLC (“Great Basin”), announced that they have entered into a memorandum of understanding (“MOU”) where WAPA may partner with Great Basin to develop the Southwest Intertie Project (“SWIP”). While the MOU will not affect Great Basin’s current open season for SWIP, a partnership with WAPA could allow construction to start while arrangements for the sale of capacity to third-party shippers are being negotiated.
Under the American Reinvestment and Recovery Act, WAPA was allocated $3.25 billion to invest in “shovel-ready” transmission projects. WAPA has been reviewing over 200 projects based on their readiness, economic impact, and project developer’s financial stability. For the SWIP project, WAPA has the option to lend money, take on an equity stake, become a customer, or agree to any combination of these three options.
SWIP is a proposed 500-mile, 500 kV transmission line that will run from Southern Idaho, through eastern Nevada, and into the Las Vegas area. Current plans may allow construction to begin later this year and have the first phase of the project, which runs from Las Vegas to northern Nevada online in 2011. A second phase to extend the line into Idaho could be finished sometime in 2012. Great Basin’s open season for long-term transmission capacity has already generated more interest than initially expected.
LS Power is also applying for permits for its Southern Nevada Intertie, a 60-mile line that would connect the southern end of SWIP to the Eldorado substation, which allows interconnections to both Arizona and California. LS Power currently plans on having the Southern Nevada Intertie in service by 2012.
WAPA previously funded the 214-mile, 230 kV Montana-Alberta Tie transmission line. While the Montana-Alberta Tie transmission line costs $220 million, SWIP is estimated to cost between $750 million and $1 billion.