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Power - Wind turbine - 63,700 kW / United States of America
Case study assignment
You are the power manager of a small public electric utility located in Washington State, USA. Several small public utilities, including your own, have been invited by a public power resource developer to purchase power from a proposed wind power project. You have been asked how much of this wind power your utility is interested in purchasing, if any.
Your utility has enough hydropower generation capacity to meet its peak load, but lacks enough water flow to produce all the required energy all the time. For example in drought periods, there are times when your utility must buy power from the market to supplement its generation that are roughly as common as when your utility sells its surplus power into the market.
Your options are to continue buying power from the market when needed, or to acquire additional resources to supplement your utility's hydropower. By acquiring wind power, you assume your utility would have more power during drought periods to protect it from purchasing power from the market when prices are high.
Site information
The site proposed by the developer is in southeast Washington State. Located in wheat fields on a high bench overlooking Kennewick, Washington, it is about 340 km east of Portland, Oregon, along the Columbia River Gorge. The bench is roughly perpendicular to the dominant winds, which are channelled through the Columbia River Gorge from the southwest.
A 64 MW wind farm consisting of forty-nine 1.3 MW Siemens Bonus turbines is planned for the site placed in four rows to intercept the prevailing southwest wind. An engineering analysis based on monitored data and the proposed turbine layout suggests that the farm would have a capacity factor of 31.4%.
The developer has options to lease the necessary land from the area's wheat farmers. The leases would cover 2,070 hectares of land, of which only 20 hectares are taken up by turbines, project facilities, roads, etc. The lease guarantees local wheat farmers an annual income for the life of the project.
About 10 km of underground power cables would be constructed to connect the four rows of wind farms to a new power substation near a major 115 kV transmission line.
Your utility is located 320 km away from the proposed site. Contractual arrangements with a large power transmission agency to transmit the wind power would have to be arranged. Your utility will also need to set up a revised service agreement with your utility's Load Control Area (LCA) operator to integrate this wind power into your utility's resource portfolio and to balance loads and resources on a real-time basis.
The project under consideration is the Nine Canyon Windfarm that when completed would be the largest wind project by public power utilities in the United States. Several public power utilities have signed a letter of interest with the developer, with the biggest interest being made by your utility for 25% of the project's output, or roughly about 7% of your utility's annual energy requirements. This relatively large amount of power would diversify the utility's primarily hydropower resource. You have to decide based on the following information whether your utility should commit to 25% of the project.
Financial information
The developer proposes to develop the site in two phases with total financing of $92 million. The purchasers are all non-profit public utilities. The project would be financed by tax-exempt bond issues carrying an estimated 6% interest rate.
The developer proposes to charge $35/MWh initially; this price would escalate at 3% per year through the life of a 22-year power purchase contract. This would result in an average cost to the purchasers of $50/MWh over the life of the contract.
In addition, a nominally $18/MWh federal government Renewable Energy Production Incentive, or "REPI" credit, is available to the developer for the first 10 years of project operation. In past years, the United States Congress has not fully funded the REPI, so the developer estimates that the actual realizable benefit is only $15/MWh. The US federal government has not fully funded the REPI, such that it can provide revenues for public power in lieu of the federal tax incentive that for-profit utilities receive for wind power projects. Ultimately, the project financing plan may have to adjust upwards the cost in a future year to make up for the REPI shortfalls that have occurred so far.
The developer's pre-feasibility annual cost estimate, including operation and maintenance, land lease, insurance, etc., is around $2,500,000 per year. The developer uses a 7% discount rate.
Considering the project from the utility's perspective, perform a RETScreen study, documenting any assumptions, and report on the significant conclusions.
Solution
The worked-out solution is the data file selected from within the RETScreen Project Database. The user automatically downloads the Project Database file while downloading the RETScreen software.
Teacher's notes
Case study assignment
You are the power manager of a small public electric utility located in Washington State, USA. Several small public utilities, including your own, have been invited by a public power resource developer to purchase power from a proposed wind power project. You have been asked how much of this wind power your utility is interested in purchasing, if any.
Your utility has enough hydropower generation capacity to meet its peak load, but lacks enough water flow to produce all the required energy all the time. For example in drought periods, there are times when your utility must buy power from the market to supplement its generation that are roughly as common as when your utility sells its surplus power into the market.
Your options are to continue buying power from the market when needed, or to acquire additional resources to supplement your utility's hydropower. By acquiring wind power, you assume your utility would have more power during drought periods to protect it from purchasing power from the market when prices are high.
Site information
The site proposed by the developer is in southeast Washington State. Located in wheat fields on a high bench overlooking Kennewick, Washington, it is about 340 km east of Portland, Oregon, along the Columbia River Gorge. The bench is roughly perpendicular to the dominant winds, which are channelled through the Columbia River Gorge from the southwest.
A 64 MW wind farm consisting of forty-nine 1.3 MW Siemens Bonus turbines is planned for the site placed in four rows to intercept the prevailing southwest wind. An engineering analysis based on monitored data and the proposed turbine layout suggests that the farm would have a capacity factor of 31.4%.
The developer has options to lease the necessary land from the area's wheat farmers. The leases would cover 2,070 hectares of land, of which only 20 hectares are taken up by turbines, project facilities, roads, etc. The lease guarantees local wheat farmers an annual income for the life of the project.
About 10 km of underground power cables would be constructed to connect the four rows of wind farms to a new power substation near a major 115 kV transmission line.
Your utility is located 320 km away from the proposed site. Contractual arrangements with a large power transmission agency to transmit the wind power would have to be arranged. Your utility will also need to set up a revised service agreement with your utility's Load Control Area (LCA) operator to integrate this wind power into your utility's resource portfolio and to balance loads and resources on a real-time basis.
The project under consideration is the Nine Canyon Windfarm that when completed would be the largest wind project by public power utilities in the United States. Several public power utilities have signed a letter of interest with the developer, with the biggest interest being made by your utility for 25% of the project's output, or roughly about 7% of your utility's annual energy requirements. This relatively large amount of power would diversify the utility's primarily hydropower resource. You have to decide based on the following information whether your utility should commit to 25% of the project.
Financial information
The developer proposes to develop the site in two phases with total financing of $92 million. The purchasers are all non-profit public utilities. The project would be financed by tax-exempt bond issues carrying an estimated 6% interest rate.
The developer proposes to charge $35/MWh initially; this price would escalate at 3% per year through the life of a 22-year power purchase contract. This would result in an average cost to the purchasers of $50/MWh over the life of the contract.
In addition, a nominally $18/MWh federal government Renewable Energy Production Incentive, or "REPI" credit, is available to the developer for the first 10 years of project operation. In past years, the United States Congress has not fully funded the REPI, so the developer estimates that the actual realizable benefit is only $15/MWh. The US federal government has not fully funded the REPI, such that it can provide revenues for public power in lieu of the federal tax incentive that for-profit utilities receive for wind power projects. Ultimately, the project financing plan may have to adjust upwards the cost in a future year to make up for the REPI shortfalls that have occurred so far.
The developer's pre-feasibility annual cost estimate, including operation and maintenance, land lease, insurance, etc., is around $2,500,000 per year. The developer uses a 7% discount rate.
Considering the project from the utility's perspective, perform a RETScreen study, documenting any assumptions, and report on the significant conclusions.
Solution
The worked-out solution is the data file selected from within the RETScreen Project Database. The user automatically downloads the Project Database file while downloading the RETScreen software.
Teacher's notes
- Correlation between drought periods and lack of wind: Data from this project indicate that in the Pacific Northwest region drought periods tend to coincide with low wind periods. The following chart shows a very good correlation (The three year correlation is very close, but it needs another year to see how tight the correlation really is.) between the Nine Canyon Wind Project's output, in terms of percent of forecast average levels, and the Columbia River's snow pack runoff from January to July, also as a percentage of the average. The Columbia River normally has about 132 billion cubic metres of snow pack water runoff during this period. This runoff is closely watched by local utilities since the Columbia River's January to July snow pack runoff is used as a gauge of the area's hydropower energy capability for that water year.
- High prices correlated with periods of low hydro and wind resources: This project has shown that market prices in the region tend to be high during drought periods. The above chart suggests that lower stream flows can be a major factor in causing higher power prices in the Pacific Northwest region. As the stream flows fell from 2003 to 2004, there was a 22% rise in non-firm power prices, and a 37% rise from 2004 to 2005. It should be noted that this price movement cannot be attributed solely to low stream flows. Power prices were high throughout the United States in 2005, affecting regional prices.
Results
This project's results and analysis are based on the experience of the Okanogan Public Utility District (PUD) in Washington State USA for integrating wind and hydro power systems. Okanogan PUD did decide to purchase a 25% share in the 64 MW Nine Canyon Wind Farm starting in 2002. The PUD's hydro resources with their flexible ramp rates and access to storage are particularly effective at firming the energy output of wind production.
The developer, Energy Northwest is a joint operating agency created to develop generation resources for its member Public Utility Districts in the State of Washington, USA. Energy Northwest, financed the windfarm project in two phases: Phase I involved a $70 million tax-exempt bond issue in 2001 to cover the first 37 wind turbines with commercial operation in September 2001; the second phase 12 turbines were financed with a $21.7 million bond issue in 2003 and was completed by December 2003.
The Windfarm's purchase agreement assumed a 3% per year annual increase in the power purchase price over the life of the 22-year contract. If the rate of increase in market power prices were to be 3% per year also, then the purchase from the Energy Northwest would be expected to cost the same as purchasing from the market.
System description
The project uses forty-nine 1.3 MW turbines from Bonus Energy of Denmark; it has a capacity of 63.7 MW and a predicted 31.4% average capacity factor. Thus, the project should produce about 175,000 MWh/year at the turbines with average capacity of 20 MW.
The project's underground 34.5 kV power lines and 115 kV substation were constructed by one of the purchasers, Benton County PUD and interconnects with the Bonneville Power Administration's (BPA) 115 kV system. Okanogan PUD's share of the Project's output is transmitted over BPA lines to Douglas PUD's Load Control Area (LCA)1. The LCA operator uses Okanogan's 65 MW's of hydropower capacity at Wells Dam on the Columbia River to smooth and make available for future use Okanogan share of the project, essentially eliminating the need to purchase additional ancillary services.
As a proxy for balancing cost we assumed an internal cost of $0.9/MWh2 for Okanogan PUD. By comparison, if this balancing service were purchased from BPA the price would be $4.50/MWh3 in part because BPA treats wind integration differently than Okanogan PUD.
Lessons learned
- First three years wind production: Total delivered wind power to the Okanogan PUD over a three year period was a little over 106,500 MWh, or 90% of expected "normal" production. This still provided roughly 7% of the utility's energy requirements. For example:
- In 2003 actual power production was 5% less than forecast with a negative net value (market value of purchases minus purchase cost) of $174,000.
- In 2004, 10% less was produced with negative net value for 2004 of $120,000.
- For 2005 production was 13% less than forecast with a positive net value of $273,000.
- First three years financial results: Okanogan PUD's average net delivered cost for wind energy was about $44.1/MWh, including an average cost of $3.2/MWh for transmission. If this electricity had been purchased at market rates, the cost would have been $43.9/MWh. The net actual value (without any assumed balancing costs) of the Okanogan PUD's wind power for the 2003 through 2005 period was negative $21,000. However, in the second half of 2005, the utility sold Renewable Energy Credits4 (REC's) for over $58,000 at a market price of $3/MWh, ($5.36/tonne of CO2 base on GHG analysis in RETScreen with 0.559 tonne of CO2/MWh). This REC sale led to a net positive value for wind power of $37,000 over the three-year period.
- Green Power Benefits: Over the life of the project, the Okanogan PUD will reduce greenhouse gas emissions, on average, by 22,000 tonnes of CO2 per year, through the displacement of fossil fuel-powered generation. The project profitability has been improved by providing monetary benefits from these emissions reductions. The utility will certainly continue selling RECs in future years.
- Correlation between drought periods and lack of wind and high prices: Data from this project indicate that in the Pacific Northwest region (where this project is located), drought periods tend to coincide with low wind periods. The Columbia River normally has about 132 billion cubic metres of snow pack water runoff during this period. This runoff is the "fuel" from winter storms and spring rains that make up the majority of the area's hydropower supply. Since September 2002, in general there has been less precipitation and less wind than normal. This apparent correlation does not help the financial feasibility of wind power in the area because drought periods are normally also high cost power periods. However, as this project demonstrated in the 2005 drought year, the net value of wind power can still be positive when reduced wind power production corresponds with higher market prices.
- Equipment Design Flaws or Malfunctions: The Nine Canyon Wind Farm has had a number of problems with its turbines. Broken gearbox teeth and bearing problems have plagued the project. There have been more than a dozen such events since commercial operation began in September 2002. There is concern that if these problems are not resolved, then project profitability will be affected once the warranty has concluded.
- REPI Credit Revenues: Revenues from the Renewable Energy Production Incentive (REPI) credit, nominally $18/MWh, have been only a bit more than 80% of what had been expected (pre-feasibility study was based on $15/MWh). The federal REPI program has provided $15/MWh amounting to ~$2,428,000 annual savings for Energy Northwest and the nine participating PUDs. The project would not be profitable if REPI credit program was not available.
- Integrating Wind Power into a Hydropower-Based Utility: The Nine Canyon Project experience has demonstrated that wind power can be integrated into a hydropower Load Control Area (LCA) with little, if any, energy imbalance capacity devoted to following wind power swings beyond that required by a utility simply following its natural load swings. This suggests that there is minimal need for additional ancillary services. For the case study, Okanogan PUD's internal balancing costs are assumed to be $0.9/MWh (~$145,000 per year); however, this price would increase to $4.5/MWh (~$728,000 per year) if this service had to be purchased from Bonneville Power Administration. (Note that this balancing cost of $0.9/MWh is added to the annual transmission costs of $3.2/MWh for the "annual O&M cost" analysis.)
- Limits on Wind Power Penetration: There is significant debate on the penetration limit of wind energy that a small utility with hydropower resources can absorb. No serious problems arise at a 11.4% power penetration level (i.e. 16 MW of wind power on a base of 140 MW of total hydropower capacity5), but at some point there could be shortcomings in the ability of hydropower to back up, shape, and accommodate the wind power without unencumbering hydropower capacity to serve load.
The State of Washington has a proposed initiative in 2006 to require large utilities to obtain 15% of their electricity from "new" renewable energy resources by 2020. Okanogan PUD is currently at about 7% of this target with its share of the Nine Canyon Wind Farm Project.
As energy prices continue to increase in the future, Okanogan PUD's wind power is expected to supplement its hydropower resources at below market prices. Although drought periods tend to be associated with lower average wind speeds, there is some wind power during these times with relatively high value which tends to compensate for the lack of wind.
Okanogan PUD is pleased with the purchase of wind plant resources to date and wind power's ability to be competitive with the market. Okanogan PUD also sees benefits in the project's ability to complement its hydropower base. The PUD will certainly consider adding more wind power to meet future power load growth, especially since the PUD's ratepayer surveys indicate they prefer cost-effective renewable energy resources over other generation resources.
Photo
Wind farm - 49 x 1.3 MW, Washington, United States of America
References
- Felton, Larry "Personal communication," Felton and Associates, 2006.
- Felton, Larry and Mainzer, Elliot, Conference paper, "Application of Wind with Hydro Resources in the NW USA", presented at the First International Conference on the Integration of Renewable Energy Sources and Distributed Energy Resources, 1st-3rd December 2004, Brussels, Belgium, Website: http://ired.iset.uni-kassel.de/files/dissemination_files/pdf/presentations/0312_1530-Felton.pdf.
- Gil, H., Deslauriers, J-C., Dignard-Bailey, L. and Joos, G., Integration of Wind Generation with Power Systems in Canada: Overview of Technical and Economic Impacts, CANMET Energy Technology Centre - Varennes technical report, February 2006, Website: http://ctec-varennes.rncan.gc.ca/fr/er_re/inter_red/p_p.html?2006-016.
- USA - Renewable Energy Production Incentive (REPI) Program information, Website: http://www.eere.energy.gov/wip/pdfs/repi2005code.pdf and http://www.eere.energy.gov/wip/program/repi.html.
1 Load Control Areas (LCA) are important "islands" within the larger power system to schedule in and out power to serve the LCA's total load with the resources within the LCA.
2 Based on "Integrating Wind Energy with the BPA Power System: Preliminary Study" by Eric Hirst, Sept-2002.
3 See link: http://www.bpa.gov/power/pgc/wind/bpa_wind_integration_services.pdf.
4 Renewable energy credits (REC's) are also known as "Green Tags". An REC is a tradable unit representing the environmental benefits associated with 1 MWh of renewable energy.
5 Okanogan's total peak load is served by approximately 65 MW's of Wells Dam capacity, 75 MW's of BPA's "Slice Product" which is primarily hydropower, and a BPA "Block Product" with up to 25 MW's.
