DOE and Interior Announce $26.6 Million for Hydropower R&D
At the National Hydropower Association conference in Washington, D.C. earlier this week, Department of Energy ("DOE") Secretary Steven Chu and Department of the Interior ("DOI") Secretary Ken Salazar announced a $26.6 million grant program to advance the development, testing, validation, modeling, and interconnection of advanced conventional hydropower systems. The agencies' news came at the same time that the DOE's Oakridge National Laboratory announced that as much of 12.6 GW (12,600 MW) of additional hydropower capacity can be drawn from the nation's waterways if generating facilities are added to 54,000 dams (including federal projects) that currently do not have them. The top 100 of those sites could add up to as much as 8 GW (8,000 MW) of capcity.
Topics 1, 2, and 3 of the Funding Opportunity Announcement (DE-FOA-0000486) will be funded by the DOE's Office of Energy Efficiency and Renewable Energy ("EERE"). Topic 4 will be jointly funded by the EERE and the DOI's Bureau of Reclamation. The topics are as follows:
- Topic 1. Sustainable Small Hydropower. $10.5 million over three years to advance research and development of small hydropower facilities to be installed at existing facilities (e.g., dams, conduits).
- Topic 2. Sustainable Pumped Storage Hydropower. $11.875 million over four years to provide assistance to projects already in development. Preference will go to projects that will begin construction in 2014 and assist with grid integration of variable resources like wind and solar.
- Topic 3. Environmental Mitigation Technologies for Conventional Hydropower. $2.25 million over three years for R&D related to issues facing conventional hydropower technologies (e.g., turbine efficiencies and fish mortality).
- Topic 4. Advanced Hydropower System Testing at a Bureau of Reclamation Facility. $2 million over three years for system testing of low-head hydropower technologies at existing, non-powered Bureau of Reclamation facilities.
Letters of Intent for the FOA are due no later than 11:59 p.m. Eastern Time on May 5, 2011. Applications are due no later than 11:59 p.m. Eastern Time on June 6, 2011.
Reclamation Issues Draft Resource Assessment of Existing Hyrdo Facilities
Last week, the U.S. Department of the Interior's Bureau of Reclamation ("Reclamation") issued a draft report titled "Hydropower Resource Assessment at Existing Reclamation Facilities" (the "Resource Assessment") for public comment. The Resource Assessment provides information on 530 exiting Reclamation sites and makes a preliminary determination about whether or not hydropower development at each facility would be economically viable.
To determine economic viability, Reclamation developed a Hydropower Assessment Tool which requires simple inputs of daily flows, headwater and tail water elevations. According to Reclamation, the result is "valid information on potential hydropower production and economic viability." Although the Resource Assessment does not claim to provide feasibility-level analyses for the sites, it does consider potential regulatory constraints related to water supply, fish and wildlife considerations, effects on Native Americans, water quality, and recreation, and adds the cost of mitigation to a projected total development cost for each site. The Resource Assessment also provides benefit-cost ratios that both include and exclude renewable energy incentive prices.
Importantly, Reclamation stated that the Resource Assessment is "targeted towards municipalities and private developers that could further evaluate the potential to increase hydropower production at Reclamation sites." This is an indication that the federal government does not intend to develop the 192 sites that Reclamation identified as having hydropower potential. Although this in itself is good news for developers, there's more. For many of the Reclamation sites, developers would proceed under a Lease of Power Privilege Agreement rather than the Federal Energy Regulatory Commission licensing process set out in Part I of the Federal Power Act. Such a lease would allow the developer to use the Reclamation facility for the purpose of generating electricity for up to 40 years.
Comments may be submitted to Mr. Michael Pulskamp, Bureau of Reclamation, Denver Federal Center, Bldg. 67, P.O. Box 25007, Denver, Colorado 80225, or email to mpulskamp@usbr.gov. Comments must be submitted by December 6, 2010.
A National Renewable Energy Standard Bill Surfaces in DC
Sens. Jeff Bingaman (D-NM) and Sam Brownback (R-KS), with Sens. Byron Dorgan (D-ND), Susan Collins (R-ME), Tom Udall (D-NM), Mark Udall (D-CO) and others joining, announced today that they will introduce a stand-alone Renewable Electricity Standard (RES) bill. The bill will require sellers of electricity to obtain the following milestones in adding renewable energy resources or energy efficiency:
2012-2013 - 3%
2014-2015 - 6%
2017-2018 - 9%
2019-2020 - 12%
2021 - 2039 -15%
Renewable resources that can be used toward compliance will include wind, solar, ocean, geothermal, biomass, landfill gas, incremental hydropower, hydrokinetic, new hydropower at existing dams, and waste-to-energy. For utilities that are unable to meet their RES targets, the bill proposes to charge a compliance payment at a rate of 2.1 cents per kilowatt hour, with such amounts then being used for renewable energy development or to offset consumers' bills.
A first step, yes. But a small one.
Follow the link to learn more:
Colorado Signs MOU for Small Hydro Development with FERC
On August 25, 2010, the Federal Energy Regulatory Commission ("FERC") and the State of Colorado signed a Memorandum of Understanding ("MOU") which could lead to simplified procedures and regulations for authorizing small-scale hydropower development in Colorado. Although traditional hydropower has not seen significant new development in recent years, interest in small, low-impact projects is on the rise across the country.
In Colorado, federal surveys have identified several hundred potential small-scale hydropower projects under five megawatts (5 MW), which could have a combined capacity of more than 1,400 MW. These new projects, if developed, could provide a needed boost for the state: on March 22, 2010, Colorado again increased its Renewable Energy Standard, requiring investor-owned utilities to procure 30% of their total retail sales from renewable resources by 2020.
Under the MOU, "Colorado proposes to implement a pilot program to identify and test opportunities to simplify and streamline procedures and regulations for authorizing small scale hydropower projects in an environmentally sound manner." The pilot process would require the State to prescreen projects to ensure that they qualify for either of the two exemptions from FERC's licensing provisions under Part I of the Federal Power Act: (1) the conduit exemption and (2) the 5 MW exemption. While only facilities being added to existing infrastructure will qualify for the pilot program, the benefits for those projects are marked. So long as Colorado state and federal resource agencies and any affected Indian tribe waive compliance with the consultation requirements of 18 CFR section 4.38(e) for a project prescreened by the State, FERC will waive the first and second stages of consultation in 18 CFR sections 4.38(b) and (c). The pilot program will continue until 20 projects have gone through the program.
While FERC's offer to waive consultation may be considered a symbolic gesture because it is conditioned on a "first move" by the State and other federal agencies, the MOU still represents an effort by the agency to develop innovative ways to streamline new, small-scale hydropower development in Colorado.
NOTE: Nothing in the MOU prevents a developer from proceeding through the traditional FERC licensing and exclusion process outside of the pilot program.
FERC Comments on Electric Storage Technologies Due August 9
Just a friendly reminder that the deadline to submit comments to the Federal Energy Regulatory Commission (“FERC”) on electric storage technologies is just around the corner. In its Request for Comments Regarding Rates, Accounting and Financial Reporting for New Electric Storage Technologies, FERC’s Office of Energy Policy and Innovation seeks comments on the following issues:
- The use of and rate treatment for storage facilities, including when it is appropriate to classify a storage facility as a transmission asset.
- The mechanisms by which a storage project that is used for multiple purposes may be compensated. Specifically, FERC seeks comment on whether a storage project may be compensated as transmission (e.g. for supporting unbundled transmission service by supplying reactive power) and also be compensated for providing ancillary services or for enhancing the value of merchant generation (e.g. by shifting output from an off-peak period to an on-peak period).
- The possibility of creating a stand-alone contract storage service and whether the storage provider would provide the service of electricity storage, enabling its customers to determine how to use their contracted share of the storage.
- Whether new accounting and reporting requirements should be created in order to facilitate cost of service or other rate policies for new storage technologies, such as chemical batteries and flywheels.
In addition to the issues outlined above and other specific questions posed by FERC in its Request for Comments, FERC invites comments on other related aspects of the storage issues not specifically addressed by FERC in the above-referenced document. Comments are due on Monday, August 9, 2010 and should reference Docket No. AD10-13-000.
Senators Propose Making Energy Storage Property Eligible for ITC & CREBs
Last week, Senators Jeff Bingaman (D-NM), Ron Wyden (D-OR), and Jeanne Shaheen (D-NH), introduced legislation that would add grid-connected energy storage property to the list of technologies eligible for the federal investment tax credit (the "ITC"). Under the Storage Technology for Renewable and Green Energy Act of 2010 (the "STORAGE 2010 Act"), eligible energy storage property would include hydroelectric pumped storage and compressed air energy storage, regenerative fuel cells, batteries, superconducting magnetic energy storage, flywheels, thermal energy storage systems and hydrogen storage. Systems that can sustain a power rating of at least one megawatt for a minimum of one hour would be eligible for a 20% tax credit under the ITC program. Should the bill become law, the tax credit would provide significant assistance to intermittent energy resource developers that are seeking new ways to shape and firm their projects' output.
The STORAGE 2010 Act would limit the available credits to $1.5 billion, and no single project may be allocated more than $30 million.
Importantly, the bill creates special extended deadlines for hydroelectric pumped storage facilities. Whereas the majority of energy storage property considered under the bill would be required to be placed in service within two years of the date the ITC was allocated, pumped storage facilities would have three years to secure required licenses and permits, five years to begin construction, and eight years to be placed in service.
Compressed air energy storage systems would enjoy similar extended deadlines- i.e., would be reqired to begin construction within three years and be placed in service within five years.
The bill would also allow grid-connected energy storage property to qualify for Clean Renewable Energy Bonds under section 54C of the Internal Revenue Code. The full text of the bill can be viewed here.
Release of the "Western Wind and Solar Integration Study"
The National Renewable Energy Laboratory ("NREL") recently announced the release of the "Western Wind and Solar Integration Study" (the "WWSIS"), which investigated the operational impact of up to 35% energy penetration of wind, photovoltaic, and concentrating solar power on the power system operated by the WestConnect group of utilities in Arizona, Colorado, Nevada, New Mexico and Wyoming. The WestConnect group includes the following: Arizona Public Service, El Paso Electric Co., NV Energy, Public Service of New Mexico, Salt River Project, Tri-State Generation and Transmission Cooperative, Tucson Electric Power, Western Area Power Administration, and Xcel Energy.
The WWSIS was prepared by GE Energy and conducted over two and a half years by a team or researchers in wind power, solar power, and utility operations. The WWSIS was designed to answer questions that utilities, Public Utility Commissions, developers, and regional planning organizations had about renewable energy use in the West, such as:
- What is the operating impact of up to 35% renewable energy penetration and how can this be accommodated?
- How does geographic diversity help to mitigate variability?
- How do local resources compare to remote, higher quality resources delivered by long distance transmission?
- Can balancing area cooperation mitigate variability?
- How should reserve requirements be modified to account for the variability in wind and solar?
- What is the benefit of integrating wind and solar forecasting into grid operations?
- How can hydro generation help with integration of renewables?
Based on the technical analysis performed in the WWSIS, it was determined that it is operationally feasible for WestConnect to accommodate 30% wind and 5% solar energy penetration, assuming that certain changes to current practice are made over time. A summary of some of the changes items identified in the WWSIS were outlined in the Executive Summary and include the following:
- Substantially increase balancing area cooperation or consolidation, real or virtual;
- Increase the use of sub-hourly scheduling for generation and interchanges;
- Increase utilization of transmission;
- Enable coordinated commitment and economic dispatch of generation over wider regions;
- Incorporate state-of-the-art wind and solar forecasts in unit commitment and grid operations;
- Increase the flexibility of dispatchable generation where appropriate (e.g., reduce minimum generation levels, increase ramp rates, reduce start/stop costs or minimum down time);
- Commit additional operating reserves as appropriate;
- Build transmission as appropriate to accommodate renewable energy expansion;
- Target new or existing demand response programs (load participation) to accommodate increased variability and uncertainty;
- Require wind plants to provide down reserves.
Finally, the WWIS also identified a number of areas where further study is warranted:
- Characterization of the capabilities of the non-renewable generation portfolio in greater detail (e.g., minimum turndown, ramp rates, cost of additional wear and tear);
- Changes in non-renewable generation portfolio (e.g., impact of retirements, characteristics, and value of possible fleet additions or upgrades);
- Reserve requirements and strategies (e.g., off-line reserves, reserves from non-generation resources);
- Load participation or demand response (e.g., functionality, market structures, PHEV);
- Fuel sensitivies (e.g., price, carbon taxes, gas contracts and storage, hydro constraints and strategies);
- Forecasting (e.g., calibration of forecasting using field experience, strategies for use of short-term forecasting);
- Rolling unit commitment (e.g., scheduling units more frequently than once on a day-ahead basis);
- Transmission planning and reliability analyses (e.g., transient stability, voltage stability, protection and control, intra-area constraints and challenges);
- Hydro flexibility (e.g., calibration of hydro models with plant performance).
