EPRI's Call to Action: It's Time for Grid Operating System 3.0
The Electric Power Research Institute (“EPRI”) recently released the smart grid white paper: “Needed: A Grid Operating System to Facilitate Grid Transformation.” The white paper dissects the first two distinct phases in grid operating systems and then calls for the creation of the 3rd. In order to support the “tectonic changes” already happening in the power system, EPRI offers to help fund, facilitate and catalyze the development of the architecture and functional specifications for Grid 3.0. Without this development, EPRI argues, “the full value of a lot of individual technologies like electric vehicles, electricity energy storage, demand response, distributed resources, and large central station renewables such as wind and solar will not be fully realized.”
In the Grid Operating System 1.0 as dubbed by EPRI, Edison and Westinghouse first faced the challenge of balancing generation against load in primitive grid operating systems of the 1800s. Grid Operating System 2.0 came about as a result of several evolutionary steps in the power markets including: 1) the transition to balancing multiple generators with a network of loads, 2) the coordination of the several large interconnected power grids across the U.S. in the 1960s, and then more recently 3) the introduction of wholesale electricity markets which shifted systems from managing dozens to hundreds of transactions a day. The Grid Operating System 2.0, or energy management system, was a computer-based operating system developed to manage supply and demand between many market participants, multiple bulk power generators and many interconnections. While Grid 2.0 became quite sophisticated and allowed system operators to monitor and control the system in real time, it was developed for a society dependent on central station power plants and primarily a one-way flow of electricity on the grid.
Although tomorrow’s power system will still depend heavily on central station power plants, it will also increasingly include renewable generation, electric energy storage, distributed generation, electric vehicles, and the increasing deployment of smart meters, phasor measurement units, sensors and electronic communication. Namely tomorrow’s grid will need to manage a widely distributed system with many disparate components, increasing participants and a two-way flow of electricity and information.
The report calls for the development of the system architecture to be based on open-source design and outlines key components that it must include:
- Hierarchical geospatial data acquisition and maintenance architecture;
- The integration of traditional utility operating data with non-traditional data such as smart meters;
- Advanced protection and control functions to prevent degradation;
- State measurement and look ahead capability;
- Cyber security;
- Technology to enable active participation by consumers;
- The ability to accommodate all generation and storage options
- Cost benefit tradeoffs to consumers by allowing bids for competitive services;
- Asset optimization;
- The capacity to self-heal or respond to and mitigate system disturbances;
- Infrastructure more resilient to attack and natural disaster; and
- The capability to effectively integrate local energy networks.
The report authors argue that the industry has a unique opportunity to develop this system through the collaborative engagement of stakeholders, rather than regional transmission operators separately contracting with different vendors. EPRI offers to engage a diverse set of stakeholders, including some of the best minds in the industry, to develop a 24-month vision of the systems architecture and requirements.
FERC Finds an Interconnection Facility Requires an OATT
Update by Sara Bergan and Jason Johns
The Federal Energy Regulatory Commission (FERC) recently issued an order rejecting a Common Facilities Agreement (CFA) under section 205 of the Federal Power Act (FPA) and related request for waiver from open access requirements. The CFA between Sky River and Windstar Energy involved a 9-mile, 230 kV generator tie-line in California known as the Wilderness Line. Sky River owns and operates a 77 MW wind facility and has an interest in the Wilderness Line along with several other Qualifying Facilities (QFs).
Windstar is developing a 60 MW wind facility for which it already has a generator interconnection agreement with SoCal Edison and the California ISO. Sky River entered into the CFA with Windstar to license a portion of Sky River’s interest in the Wilderness Line to enable the output from Windstar’s wind facility to reach the point of interconnection with SoCal Edison. In other words, the CFA served to support Windstar’s interconnection with SoCal Edison. Sky River sought approval of the CFA and the open access waivers on the basis that the gen-tie line is not an integrated component of the grid and was designed solely as an interconnection line.
FERC did not accept the CFA or the waiver from the open access transmission tariff (OATT) filing requirement. FERC determined that the CFA was an “attempt to govern transmission service for an unaffiliated third party over the Wilderness Line outside the context of an OATT, with all its attendant rights and obligations.” Further FERC noted that waiver of obligation to file an OATT applies only until such time as a request for transmission service is made and that any transmission over the Wilderness Line for non-owners must be made pursuant to an OATT.
Texas Court of Appeals Hands Down Decision in Important Wind Curtailment Case
On July 27, 2010, the Court of Appeals of Texas, Fifth District, Dallas, issued its decision in TXU Portfolio Management Company, L.P., v. FPL Energy, LLC, et al., 2010 Tex. App. Lexis 5905 (2010). The case arose when three FPL wind farms (the "Wind Farms") located in the McCamey area of West Texas experienced ERCOT-imposed generation curtailments imposed by the Electric Reliability Council of Texas ("ERCOT") during 2002-2005. The Wind Farms had each entered into a power purchase agreement (“PPA”) with TXUPM under which they agreed to deliver a minimum quantity of energy and renewable energy credits (RECs) each year. Because of the deficiencies caused by the ERCOT generation curtailments, TXUPM sued the Wind Farms for deficiency damages under the PPAs. The Wind Farms counterclaimed, asserting that TXUPM materially breached each of the PPAs by failing to insure enough "transmission capacity" to allow the three wind farms to generate and deliver all of the electricity they were theoretically able to generate given wind conditions.
Section 2.03 of the PPAs required TXUPM to arrange for "all services, including without limitation Transmission Services . . . necessary to deliver Net Energy." The Texas Court of Appeals concluded that this provision required TXUPM to supply transmission service sufficient to accept delivery of energy actually generated by the project and delivered to the interconnection point. Contrary to the Wind Farms' argument, however, Section 2.03 did not require TXUPM to make sure there was enough transmission capacity in the McCamey area to make sure that the three wind plants could in fact generate every MWh they were theoretically capable of generating given wind conditions.
This outcome is not too surprising--it would have been very unusual had the Court of Appeals concluded that an offtaker's duty to supply transmission services at the delivery point amounted to an implied duty to arrange for the construction of (very expensive) transmission infrastructure sufficient to avoid generation curtailments. Utilities everywhere can breathe a sigh of relief that the Court of Appeals did not read this duty into the PPAs.
The fact that the Wind Farms had failed to deliver enough output to meet the annual minimum quantities specified in the three PPAs was not in dispute. Since the court concluded that TXUPM had not breached the PPAs by failing to supply transmission capacity, the only remaining question was the calculation of damages.
Stepping away from the court’s decision for a moment, though, it’s worth noting that there's a separate provision that is typically included in PPAs for intermittent renewable energy, and it apparently was not included in the three PPAs in dispute here, perhaps because of their 2000-2001 vintage. An annual minimum output guarantee requires a wind developer to take both mechanical availability risk and wind risk--the plant's output can be reduced below the minimum level if the wind doesn't blow as hard or as often as expected, or if the wind turbines and other equipment are not available as often as they should be. However, these risks are to some extent within the developer's control--wind risk can be addressed by thorough wind studies, and mechanical availability can be managed using the developer’s O&M program. Generation and transmission curtailment, on the other hand, are typically outside the developer's control and can be affected by delays in completing transmission infrastructure, additions of other intermittent resources to the grid, routine maintenance of the transmission system, emergencies and other factors.
Recognizing this, renewable energy PPAs usually provide that curtailed energy is counted as if it were generated for purposes of determining whether a plant has achieved its output guarantees. Although the requisite language is often omitted from utility pro forma renewable PPAs, most utilities are willing to agree if pressed that energy that could have been generated but for curtailment(s) should be counted as if it were generated for purposes of testing the project’s output guarantee. There may be a little scuffling over the proper method for calculating the quantity of energy and RECs that would have been generated “but for” the curtailment, but the real fight is usually over whether the PPA is in whole or in part a "take or pay" contract in which the utility is required to pay for some or all of the output that is actually curtailed. Cf. FPL Energy Upton Wind I, L.P., v. City of Austin, 240 SW3d 456 (2007), reh’g denied 2007 Tex App LEXIS 9306 (Tex App Amarillo 2007) (the Texas Court of Appeals ruled that ERCOT-imposed curtailments are not the same as voluntary economic curtailments by the power purchaser under a PPA and thus are not curtailments that the purchaser must pay for).
In any case, the Wind Plants in this case did not receive credit for curtailed energy under the three PPAs, so the court considered the deficiency as a given and turned to calculating the amount of damages. The three PPAs had hard-wired $50/MWh as the liquidated damage payment due for each MWh of deficiency below the annual output guarantee. This number was based on the per MWh penalty the Texas PUC was expected to impose, as of the time the PPA was entered into, on utilities that failed to secure enough renewable energy. The Wind Plants argued that this amount bore no resemblance to TXUPM's cover damages at the time of the alleged breach and had persuaded the trial court to declare the liquidated damages clause to be unenforceable. The Texas Court of Appeals reversed, concluding that the Wind Farms had failed to prove (1) that a measure of damages was ascertainable when the PPAs were entered into, or (2) that the $50/MWh rate was an unreasonable estimate of TXUPM's actual damages.
Using the deficiency rate of $50/MWh and the Wind Farms' total net deficiencies of 580,465 MWh for 2002 through 2005, TXUPM claimed $29,023,250 in deficiency damages. Bear in mind that these are just the deficiency damages, and thus only a part measure of the pain the plants suffered--they also had to forego a sale at the contract price and lost a Production Tax Credit (PTC) on each MWh curtailed. For utilities that are slow to acknowledge that curtailment risk is an important issue for the intermittent energy developer, this case offers a very succinct $29 million dollar explanation of why developers, lenders, and equity care so much about the topic.
FERC Determines That Battery Storage Devices Qualify as Transmission Facilities. Is the Door Open for Other Energy Storage Devices?
In late January, FERC issued an order in response to a filing by Western Grid Development LLC that asked FERC to declare that Western Grid's proposed battery storage devices are transmission facilities eligible for certain rate incentives. Western Grid described its battery technology as 10 to 50 MW sodium sulfur batteries that would be installed at strategic places on the California ISO transmission grid in order to provide voltage support and protect against transmission overloads. In a description that seemed significant to FERC, Western Grid stated that its batteries would only enhance transmission reliability at the California ISO's direction, and that the batteries would not operate or participate in energy markets or provide electricity for commercial sale.
FERC examines energy storage devices on a case-by-case basis because storage devices don't fit squarely within the traditional transmission, distribution, or generation categories of assets. In this case, FERC gravitated to the notion that the battery devices would not provide capacity or energy to be sold in the energy market, and that Western Grid would not retain any revenues outside of the transmission access charge (unlike generators). For these and other reasons, FERC distinguished Western Grid from similar filings (see Nevada Hydro II--pumped storage), and determined that Western Grid's technology will act enough like transmission assets to warrant eligibility for transmission rate incentives. FERC's approval of rate incentives, however, was conditional upon the California ISO approving Western Grid's projects in the transmission planning process.
Although FERC repeated numerous times that its decision was based on the "specific circumstances and characteristics" of Western Grid's projects, the order shows potential for energy storage devices. If such devices can show that they act sufficiently like traditional transmission assets (like capacitors), they may be able to obtain very valuable transmission rate incentives. Whether this opens the door for compressed air energy storage and pumped hydro (but see Nevada Hydro II) is still up in the air, but rest assured that these questions will be at FERC before too long.
Show me the Money: $343 Million Deployed to Transmission Project in Washington and Oregon
The Department of Energy has announced that $343 million from the American Recovery and Reinvestment Act has been provided to the Bonneville Power Administration's ("BPA") McNary-John Day transmission project (the "McNary-John Day Line") in Washington and Oregon.
The McNary-John Day Line runs 79 miles from the McNary Substation in Oregon, through Washington, and ending at the John Day Substation in Oregon. The BPA has stated that the new line will help promote wind and other renewable energy generation in the Pacific Northwest.
The McNary-John Day Line will be energized by 2012 and provide transmission service for over 575 megawatts of electricity.
2009 Utah Legislation Sets Stage for More Renewable Energy in Utah
Legislators recently adopted legislation aimed at helping Utah stay competitive with surrounding states in the fast growing national clean energy movement. Five (5) bills dealing with renewable energy and energy efficiency passed with strong bi-partisan support. Three (3) resolutions, while non-binding, send strong messages to local governments and utilities that the legislature encourages, and wants to remove barriers to, renewable energy and energy efficiency across all sectors. The success of the 2009 legislative session indicate that renewable energy will play critical roles in Utah’s future.
House Bill 430 - Economic Development Incentives for Alternative Energy Projects, is designed to attract new clean energy industries and projects to Utah. The bill allows the Governor’s Office of Economic Development (GOED) to establish energy development zones and offer tax credits to companies and projects located in those zones.
Senate Bill 76 SO3- Energy Amendments, address the barriers to renewable energy transmission by creating a political subdivision of the State tasked with the development of a master plan for renewable energy production and transmission infrastructure. This subdivision will have the ability to apply for and seek out federal grants, as well as bonding authority to pay for transmission lines for renewable energy.
Senate Joint Resolution 1 S02 Renewable Energy System, urges the Utah State Energy Program and municipal governments to collaborate on the development of model renewable energy ordinances to streamline the development process at the local government level.
Senate Joint Resolution 10 - Alternative Training Center, recognizes the need to train the growing clean energy workforce in Utah. The bill supports the establishment of an Alternative Energy Training Center in Beaver County, an area with high concentration of existing, upcoming and potential renewable energy development.
House Joint Resolution 9 - Effective Energy Efficiency and Utility Demand Side Management, recognizes energy efficiency as a priority resource and urges state and local governments and utilities to promote and encourage all available cost-effective energy efficiency and conservation, setting voluntary energy savings goals for Rocky Mountain Power and Questar Gas and expresses support for regulatory mechanisms that remove disincentives to utility energy efficiency and conservation.
