The Federal Policy Landscape Is Now More Favorable to Wind Energy than at Any Other Time in the Past Decade
From the US Department of Energy 2009 Wind Technologies Market Report released August, 2010 (With useful annotations added by Hawai`i Free Press. Kahuku shows up in paragraph 10.)
A variety of policy drivers at both the federal and state levels have been important to the expansion of the wind power market in the United States.
At the federal level, perhaps the two most important policy incentives – at least in recent years – have been the PTC (Production Tax Credits) and accelerated tax depreciation. First established by the Energy Policy Act of 1992, the PTC provides a 10-year credit at a level that equaled 2.1¢/kWh in 2009 (adjusted annually for inflation), and increases to 2.2¢/kWh in 2010. (EDITOR’S NOTE: This is why, after 10 years, the developers often cease maintenance and effectively abandon the wind farm.)
The historical importance of the PTC to the U.S. wind power industry is illustrated by the pronounced lulls in wind power capacity additions in the three years (2000, 2002, and 2004) in which the PTC lapsed, as well as the increased development activity often seen during the year in which the PTC is otherwise scheduled to expire.
Accelerated tax depreciation, meanwhile, enables project owners to depreciate the vast majority of their investments over a five- to six-year period for tax purposes. An even-more-attractive 50% “bonus depreciation” schedule was in place during 2009, serving as an incremental driver of wind capacity additions in that year.
Although these two federal incentives will likely remain important going forward (the PTC is currently in place through 2012, having been extended as part of the Recovery Act; while accelerated depreciation has no expiration date), in 2009 the PTC in particular was overshadowed by the Section 1603 Treasury cash grant program, enacted as part of the Recovery Act in February 2009.
Acknowledging the conspicuous absence of tax equity investors in the market following the financial crisis of late 2008, Section 1603 of the Recovery Act enables wind power and other qualifying projects to elect a 30% cash grant in lieu of the PTC or ITC (Investment Tax Credit).
Relative to the PTC, the 30% cash grant can provide a significant amount of value to wind power projects. Not surprisingly, then, the program has been heavily subscribed by wind farm projects, which as of mid-July 2010 had received 88% of the more than $4.78 billion in Section 1603 cash grants awarded since the program’s implementation in late-July 2009. More than 6,400 MW – i.e., more than 64% – of all new wind power capacity installed in the United States in 2009 chose the grant.
The Section 1603 program should continue to be a strong driver for at least another year – wind power projects must begin construction by the end of 2010, and be operating by the end of 2012, in order to qualify for the grant – and several proposals exist to extend the program in some form.
Two other Recovery Act programs also played a (more limited) role in the wind energy sector in 2009. First, Title IV of the Recovery Act expanded a loan guarantee program that was originally enacted as part of the Energy Policy Act of 2005. The original program, under Section 1703, is targeted at projects that manufacture or utilize innovative clean energy technologies.
The first two such guarantees for projects in the wind sector were conditionally awarded in 2009 and early 2010: Nordic Windpower received a $16 million loan guarantee to expand its two-bladed wind turbine manufacturing facility in Pocatello, Idaho, while developer First Wind received a $117 million loan guarantee for its 30 MW Kahuku wind farm project (which will include battery storage) in Hawaii.
The Recovery Act also created a sister loan guarantee program, called the Section 1705 program, for projects using commercially proven technologies, but as of mid-July 2010, no wind power projects had yet been awarded Section 1705 loan guarantees.
Second, to encourage the growth of green manufacturing jobs in the United States, the Recovery Act created an advanced energy manufacturing tax credit, also known as the Section 48C credit, which provides a 30% tax credit for investments in new clean energy manufacturing facilities. More than 500 applications seeking in excess of $8 billion in Section 48C credits were submitted by the October 2009 deadline, exceeding the $2.3 billion program cap by more than a 3-to-1 margin.
In early January 2010, 183 manufacturing projects spread across 43 states received credit allocations totaling $2.3 billion, with the wind energy sector capturing more than 10% of this total. Recipients are under no obligation to proceed with their projects, but in order to realize the credit, they must commission their facilities by February 2013. The Obama administration is seeking to extend the program for another year, with an additional $5 billion (Office of the Press Secretary, 2010).
In addition to the tax benefits and Recovery Act programs discussed above, a number of other federal policies have also helped to support different segments of the wind power industry in recent years. For example, because tax-exempt entities are unable to take direct advantage of tax incentives, the Energy Policy Act of 2005 created the Clean Renewable Energy Bond (CREB) program, authorizing $800 million of what is effectively interest-free debt (though not without certain additional transaction costs) to eligible renewable projects.
Another $400 million of “old CREBs” were authorized in late 2006, followed by $2.4 billion in “new CREBs” authorized by the Extension Act of 2008 ($800 million) and Recovery Act of 2009 ($1.6 billion). This old/new distinction is pertinent because “new CREBs” must follow a different set of rules – largely aimed at increasing the bonds’ effectiveness – than existed under the “old CREBs.”
Applications for the $2.4 billion in “new CREBs” were due in early August 2009, and in late October, $2.2 billion in CREB allocations were awarded, with more than $450 million going to wind power projects.
Finally, since 2003 the federal government has offered financial assistance to wind power (and other types of) projects that are located in rural areas. Specifically, Section 9006 of Title IX of The Farm Security and Rural Investment Act of 2002 established The Renewable Energy Systems and Energy Efficiency Improvements Program (the Section 9006 program).
Administered by the USDA, the Section 9006 program provided grants and loan guarantees to farmers, ranchers, and rural small businesses for assistance with purchasing renewable energy systems and making energy efficiency improvements.
In May 2008, the Section 9006 program was converted to the Rural Energy for America Program (the REAP) by The Food, Conservation, and Energy Act of 2008. The REAP is little changed from the Section 9006 program – i.e., the REAP still targets agricultural producers and rural small businesses (including special purpose project companies set up specifically to own wind farm projects) with grants and loan guarantees to encourage the installation of renewable energy systems and energy efficient upgrades.
Grants are limited to the lesser of 25% of the project’s cost or $500,000, whereas loan guarantees may not exceed $25 million (the combined amount of a grant and loan guarantee may not exceed 75% of a project’s cost). In 2009, the USDA awarded more than $60 million through the REAP program (only a portion of which went to wind), while applications for an additional $100 million were due by June 30, 2010.
State Policies Play a Significant Role in Directing the Location and Amount of Wind Power Development
State policies continue to play a substantial role in directing the location and amount of wind power development. From 1999 through 2009, for example, 61% of the wind power capacity built in the United States was located in states with RPS policies; in 2009, this proportion was 57%. One new state (Kansas) established a mandatory RPS program in 2009, bringing the total to 29 states and Washington D.C.; a number of additional states strengthened previously established RPS programs in 2009.
In aggregate, existing state RPS (Renewables Portfolio Standard) policies would require roughly 73 GW of new renewable capacity by 2025, representing roughly 6% of total U.S. retail electricity sales in that year and 30% of projected load growth between 2000 and 2025.
Utility resource planning requirements in Western and Midwestern states have also helped spur wind power additions in recent years (especially as the prospect of future carbon regulations has been included as a variable in resource selection), as has growing voluntary customer demand for “green” power, especially among commercial customers.
State renewable energy funds provide support for wind power projects (both financial and technical), as do a variety of state tax incentives. Finally, concerns about the possible impacts of global climate change are fueling interest by states and regions (as well as the federal government) to implement carbon reduction policies, a trend that is likely to increasingly underpin wind power expansion in the years ahead.
The Northeast’s Regional Greenhouse Gas Initiative cap-and-trade policy is now in operation, and carbon policies are also under discussion and being implemented in a number of other regions and states.
Despite Progress on Overcoming Transmission Barriers, Constraints Remain
Transmission development appears to be gaining some traction. The North American Electric Reliability Corporation (NERC), for example, projects that transmission (100 kV and above) in the United States will increase by 31,400 circuit-miles, or about 8%, by 2018 (NERC 2009a), while the Brattle Group projects that annual transmission investment will exceed $10 billion going forward, compared to roughly $2 billion per year in the mid-1990s.
Lack of transmission can be a barrier to wind power development. New transmission is particularly important for wind energy because wind power projects are constrained to areas with adequate wind speeds, which are often located at a distance from load centers.
There is a mismatch between the relatively short timeframe needed to develop a wind power project compared to the time typically required to build new transmission. Uncertainty over siting and cost allocation, particularly for multi-state transmission lines, complicates transmission development.
With regards to transmission, several decisions at the federal level in 2009 created some concern among the wind power industry:
- -The U.S. Court of Appeals ruled that FERC could use its backstop siting authority if a state withheld its decision for more than a year, but that it did not have the authority to override a state’s decision to deny a transmission permit application (U.S. Fourth Circuit Court of Appeals 2009).
- -The U.S. Court of Appeals remanded back to FERC the Commission’s decision to approve spreading the costs of new transmission facilities above 500-kV in PJM to all transmission customers. Ruling that FERC had to better document how all transmission customers would benefit from the new transmission if all had to share in the cost, the Court’s decision added some uncertainty to cost allocation policy (U.S. Seventh Circuit Court of Appeals 2009).
- -FERC conditionally approved the Midwest ISO’s petition to revise its pre-existing 50-50 cost share methodology to instead charge interconnecting generators 90% of the costs for transmission facilities rated 345 kV and above, and 100% for transmission facilities below 345 kV, though FERC also directed the Midwest ISO to file a revised cost allocation methodology by July 15, 2010 (FERC 2009). This policy contrasts with FERC’s previous approval in 2007 of a California ISO proposal in which the cost of transmission for location-constrained resources would, initially, be covered in an ISO access charge (FERC 2007a).
Nonetheless, in June 2010, FERC issued a proposed transmission cost allocation rule that, among other things, would require that local and regional transmission planning processes incorporate the transmission needs that emanate from state or federal policies (such as RPS programs) and would establish principles that cost allocation proposals from grid providers must meet. The FERC proposal also indicates that, if agreement cannot be reached on cost allocation, FERC would itself develop a cost allocation method based on the record in that particular case (FERC 2010c).
States, grid operators, regional organizations, and DOE also continue to take proactive steps to encourage transmission investment to improve access to renewable resources. A non-exhaustive list of examples of these initiatives is presented below:
- -Texas Competitive Renewable Energy Zones (CREZ): The Public Utility Commission of Texas (PUCT) encountered a slight delay with its $5 billion transmission plan for that state’s CREZs. In January 2009, the PUCT awarded the development of CREZ transmission plan segments. The city of Garland challenged the decision, and in December 2009, the Court reversed and remanded the transmission construction allocation order (District Court 2009). The PUCT subsequently assigned the uncontested transmission segments, while creating a new regulatory docket for the reconsideration of the contested transmission segments.
- -Southwest Power Pool (SPP): SPP received FERC approval for a new transmission cost allocation methodology in which costs will be paid by load and allocated between SPP and regions based on transmission voltage. Transmission projects of 300 kV and above will be funded 100% regionally across all of SPP, whereas costs for transmission projects between 100 kV and 300 kV will be allocated 1/3 regionally and 2/3 locally. Costs for transmission projects below 100 kV will be entirely recovered locally (SPP 2010). FERC’s approval paves the way for SPP to construct $1.14 billion of “Priority Project” transmission in Kansas, Missouri, Oklahoma, and Texas.
- -Bonneville Power Administration (BPA) Network Open Season: BPA’s second annual network open season was held in June 2009, resulting in 83 transmission service requests for 4,867 MW, of which 2,599 MW were for wind power projects. This process subsequently led to signed transmission agreements for 1,553 MW, including 933 MW of wind power. BPA is also constructing the 500-kV McNary-John Day project, with $3.25 billion in increased borrowing authority from the Recovery Act (BPA 2009a); the line is expected to go into service in 2012 and could support 575 MW of new wind power capacity (BPA 2009b).
- -Western Area Power Administration (WAPA): WAPA also received authority under the Recovery Act to increase its borrowing authority by up to $3.25 billion, and received over 200 transmission proposals to a WAPA-issued request. WAPA has so far made one loan of $161 million to Tonbridge Power for the Montana-Alberta Tie Transmission Line (WAPA 2009). Construction of the 230-kV line, primarily being developed to support wind power, is underway and is expected to be completed in 2011 (Tonbridge 2010).
- -Interconnection-Wide Transmission Planning: In December 2009, DOE allocated $60 million in Recovery Act funds to promote collaborative long-term analysis and interconnection-wide transmission planning for the Eastern, Western, and Texas interconnections (DOE 2009).
A variety of efforts to proactively plan for transmission, often through analyses of state and regional renewable energy zones, also continued in 2009.
Finally, progress was made in 2009 on some of the transmission projects that are designed, in part, to support wind power, including:
- -California Tehachapi: The first three segments of the Tehachapi transmission project were completed in May 2010. Meanwhile, the California PUC approved segments 4-11 in December 2009. Once fully operational, the Tehachapi transmission expansion is expected to be able to accommodate about 4,000 MW of wind power (SCE 2010).
- -Texas NextEra Transmission: NextEra built a 200+mile 345-kV line to capture the higher wholesale prices that exist outside of West Texas, where most of wind power capacity is located. The line can transmit up to 950 MW and runs southeast from two of NextEra’s wind power projects near Abilene (FPL 2009).
- -Maine Transmission: In May 2010, the Maine PUC approved a $1.4 billion proposal for a 350-mile transmission line that could provide Maine wind power projects greater access to southern New England markets (CMP 2010).
Integrating Wind Energy into Power Systems Is Manageable, but Not Free of Costs, and Market Operators Are Implementing Methods to Accommodate Increased Penetration
During the past several years, there has been a considerable amount of attention paid to the potential impacts of wind energy on power systems. Concerns about, and solutions to, these issues have affected, and continue to impact, the pace of wind power deployment in the United States
Studies that have evaluated the operational impacts of wind energy on the power system have become increasingly sophisticated, resulting in a better accounting of the potential impacts and integration costs of increased wind energy penetration levels.
Key trends among some of the more-recent studies include evaluating even higher levels of wind energy penetration, evaluating the integration of wind energy within larger electricity market areas, and identifying approaches to mitigate integration concerns. Additional recent high-level summaries and examples of wind energy integration in the United States and in other countries are available from IEEE (2009).
Two major studies of high penetrations of wind energy, each using different approaches and analysis tools, were completed in early 2010. The Eastern Wind Integration and Transmission Study (EWITS) examined land-based and offshore wind energy in the Eastern Interconnection at penetrations of up to 30% on an energy basis (EnerNex 2010). The Western Wind and Solar Integration Study (WWSIS) examined wind and solar energy in the Western Interconnection with a particular focus on the WestConnect footprint; the highest penetration examined in the WWSIS was a scenario with 30% wind and 5% solar on an energy basis within the WestConnect footprint and 20% wind and 3% solar energy in the rest of the Western Interconnection (GE 2010).
Both studies found that, with significant improvements in operational practices, it is technically feasible to operate the power system with high penetrations of wind energy.
Changes in operational practices that were found to be beneficial include increased procurement of operating reserves, greater use of sub-hourly generation scheduling, enhanced flexibility and cycling of natural gas and coal plants, incorporation of state-of-the-art wind forecasting into system operations, utilization of demand response, and increased cooperation or consolidation of balancing areas.
Although the level of detail in the transmission analysis differed between the two studies, both involved extensive transmission expansion to deliver wind energy resources to load centers and to manage the additional variability and uncertainty.
Wind penetration on a capacity basis (defined as nameplate wind power capacity serving a region divided by that region’s peak electricity demand) was frequently used in earlier integration studies. For a given amount of wind power capacity, penetration on a capacity basis is typically higher than the comparable wind penetration in energy terms (because, over the course of a year, wind power projects generally operate at a lower percentage of their rated capacity, on average, than do many other resources). The energy penetration levels in the EWITS study correspond to 48% wind on a capacity basis. (EDITOR’S NOTE: This is still absurdly high. Actual electricity production is often 10-20% of wind nameplate capacity.)
The energy penetration levels in the WWSIS study correspond to penetrations of 52% wind and 10% solar in the WestConnect and 38% wind and 6% solar in the rest of the Western Electricity Coordinating Council on a capacity basis. Similar information is presented in Figure 39 at various levels of wind power capacity penetration. Because methods vary and a consistent set of operational impacts has not been included in each study, results from the different analyses are not fully comparable. Note also that the rigor with which the various studies have been conducted varies, as does the degree of peer review. Nonetheless, key conclusions that continue to emerge from the growing body of integration literature include the following:
- -Wind energy integration costs are below $10/MWh – and often below $5/MWh – for wind power capacity penetrations up to or exceeding 40% of the peak load of the system in which the wind power is delivered. (EDITOR’S NOTE: These are the increased costs incurred in the electric generation/transmission system to accommodate fluctuating wind supplies.)
- -Regulation impacts are often found to be relatively small, whereas the impacts of wind energy on load-following and unit commitment are typically found to be more significant. Variations in estimated costs across studies are due, in part, to differences in methodologies, definitions of integration costs, power system and market characteristics, wind energy penetration levels, and fuel price assumptions.
- -Larger balancing areas, such as those found in RTOs and ISOs, make it possible to integrate wind energy more easily and at lower cost than is the case in smaller balancing areas.
- -The successful use of wind power forecasts by system operators can significantly reduce integration challenges and costs. Wind forecasts are most accurate and effective when aggregated across large, electrically interconnected areas.
- - Intra-hour scheduling (e.g., 5-10 minute schedules) provides access to flexibility in conventional power plants that lowers the costs of integrating wind energy.
- - Wind energy integration costs tend to rise with increasing natural gas prices, though the economic value of wind energy also increases with higher gas prices. (EDITOR’S NOTE: This is because natural gas powered “peaker” plants have to be kept at the ready to make up for fluctuating wind.)
Many ISOs and utilities are also continuing to take important steps to mitigate the challenges faced with integrating larger quantities of wind energy. Centralized wind forecasting systems are currently in place at the PJM, Electric Reliability Council of Texas, Midwest ISO, New York ISO, California ISO, Southern California Edison, and Xcel Energy; while the BPA is currently developing wind forecasting systems (Porter and Rogers 2010).
Northern Tier Transmission Group, Columbia Grid, and WestConnect, meanwhile, are jointly investigating projects that will increase power system flexibility, including the creation of a dynamic scheduling communications infrastructure, sharing of area control errors, and intra-hour scheduling and balancing. These initiatives have broad benefits, including better utilization of the transmission system and providing increased flexibility to integrate wind energy.
Some utilities are now directly charging wind power projects for balancing services or are reducing posted ‘avoided cost’ contract price payments to account for the costs of integrating wind energy. BPA, for example, includes a wind energy balancing charge in its transmission tariff equivalent to about $5.70/MWh. (Are you listening HELCO?)
FERC conditionally approved a higher generator regulation and frequency response services charge for wind energy in the Westar Energy balancing area equivalent to about $0.80/MWh; this tariff is still in FERC proceedings and may be revised (FERC 2010a). Idaho Power, Avista, and PacifiCorp, meanwhile, all discount their avoided cost payments for qualifying wind power projects by an integration rate that ranges from 7-9% of the avoided cost rate, up to $6.50/MWh (IPUC 2010).
At a national level, NERC (North American Electric Reliability Corporation) and FERC (Federal Energy Regulatory Commission) have also been focused on identifying methods to reliably and economically integrate wind energy into the bulk power system. NERC released a comprehensive report in 2009 with several recommendations for changing planning and operational procedures to maintain reliable operation with high levels of variable generation (NERC 2009b).
Following the report, NERC outlined a three-year work plan to further develop and improve standards and practices for integrating variable generation. FERC, meanwhile, issued a notice of inquiry seeking public comment on whether to reform any of its rules or procedures to ensure that increased amounts of variable energy resources can be accommodated with just and reasonable rates and without undue discrimination (FERC 2010b). Over one hundred reply comments have been filed by parties throughout the United States proposing potential steps to better facilitate the integration of variable generation.
General Electric (GE) remained the number one manufacturer of wind turbines supplying the U.S. market in 2009, with 40% of domestic turbine installations. Following GE were Vestas (15%), Siemens (12%), Mitsubishi (8%), Suzlon (7%), Clipper (6%), Gamesa (6%), REpower (3%), Acciona (2%), and Nordex (1%). Other utility-scale (>100 kW) wind turbines installed in the United States in 2009 (and that fall into the “Other” category in Figure 9) include turbines from NedWind (6.5 MW), AAER (6 MW), DeWind (6 MW), Fuhrlander (4.5 MW), Goldwind (4.5 MW), RRB (2.4 MW), Elecon (0.6 MW), and Wind Energy Solutions (0.25 MW).
Primary authors: Ryan Wiser, Lawrence Berkeley National Laboratory, Mark Bolinger, Lawrence Berkeley National Laboratory. With contributions from Galen Barbose, Naïm Darghouth, Ben Hoen, and Andrew Mills (Berkeley Lab), Kevin Porter and Sari Fink (Exeter Associates), Suzanne Tegen (National Renewable Energy Laboratory).
IMAGES AND GRAPHS: www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologi
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