Joe Drop
Site Location, Ownership and Access
The Joe Drop is on a lateral owned and operated by the Wheatland Irrigation District (WID). Joe Drop is near the intersection of Highway 34 and Sybille Creek Road approximately 7 miles southwest of Wheatland. The lateral supplies water to agricultural producers within the boundaries of the Wheatland Irrigation District. The WID has an easement to access and maintain the drop structure, and the existing access roads are adequate.
Water Rights
The Wheatland Irrigation District owns the water rights that would be used for hydropower production; however, the beneficial use is permitted as irrigation. WID would have to file for an enlargement to add power generation as a beneficial use to the water rights. The water right for power generation would be non-consumptive and secondary to irrigation. The need for any additional water rights is not anticipated, as the hydropower facility would utilize existing rights.
Estimated Head and Flow
The elevation difference across the drop is approximately 20 feet. Water levels upstream of the drop can vary slightly depending on the flow rate in the canal; however, for the level of this analysis, the variation in elevation was assumed to be insignificant. The length of the penstock will be very short and assumed sized to minimize friction loss; therefore, the gross head of 20 feet was also assumed to be the net head available. A more detailed analysis is required to properly determine the net head and is beyond the scope of this assessment.
The available flows in the canal were obtained from the WID. The available flow for hydropower generation is seasonal and occurs during the irrigation season assumed to be from May 15 to September 15. The minimum flow is 80 cfs, and the maximum flow is 240 cfs. The minimum flows occur early and late in the irrigation season, and the maximum flows occur during July and August. The design flow was estimated to be the maximum flow or 240 cfs, since the turbine can handle the variable flow rates fairly efficiently. Daily flow data should be obtained in future studies to accurately assess the energy generation of the hydropower facility. For this analysis, the following flow characteristics were assumed:
| Month | Average Monthly Flow |
| May | 80 cfs |
| June | 150 cfs |
| July | 240 cfs |
| August | 240 cfs |
| September | 100 cfs |
Utility Connection
The proposed hydropower facility is in a rural but fairly developed area. Several residences are within close proximity to the proposed site, and a major electrical transmission line is approximately 4,000 feet away. Smaller distribution electrical lines are along Sybille Creek Road, approximately 500 feet away. The capacity of the distribution line is unknown but was assumed to be the location of interconnect.
Political and Environmental Concerns
The proposed site is in a rural area where agriculture is the driving industry. The nearest residence is approximately one-eighth of a mile away. Noise from the turbine is not anticipated to impact the nearby residences. Since the hydro turbine would be on an existing canal and flows are already seasonal, the environmental impact associated with hydro would be very minimal. Fish and wildlife mitigation would not be required, and the federal permitting process would be streamlined and take minimal effort.
Generation and Turbine Selection
The Bureau of Reclamation’s Hydropower Assessment Tool was used to estimate capacity and energy generation of the proposed hydropower facility. Based on a rated flow of 240 cfs and a net head of 20 feet, the plant would have a design capacity of 343 kW and generate 795 MWh of energy annually. The head and flow conditions indicate the turbine would likely be a Kaplan. A cross flow turbine may be an option; however, the design flow would be on the high end of a cross-flow turbine. The following tables show the plant generation summary.
| Plant Generation Summary | |
| Plant Design Capacity (kW) | 343 |
| Number of Days | 365 |
| Data Years | 1.00 |
| Total Data Period Energy (kWh) | 795,000 |
| Average Plant Capacity (kW) | 93 |
| Plant Peak Capacity (kW) | 343 |
| Plant Factor | 0.270 |
| Plant Monthly Generation | |||
| Month | Days with Data | Average Capacity (kW) | Average Energy (MWH) |
| January | 31 | 0 | 0 |
| February | 28 | 0 | 0 |
| March | 31 | 0 | 0 |
| April | 30 | 0 | 0 |
| May | 32 | 61 | 44 |
| June | 30 | 242 | 174 |
| July | 31 | 337 | 243 |
| August | 31 | 343 | 247 |
| September | 30 | 121 | 87 |
| October | 31 | 0 | 0 |
| November | 30 | 0 | 0 |
| December | 31 | 0 | 0 |
| Annual | 795 | ||
Economics
Plant costs were generalized and based on the generator output, Bureau of Reclamation’s Cost Index, Energy Electric Power Research Institute “Quantifying the Value of Hydropower in the Electric Grid: Plant Cost Elements” and experience with similar projects. The cost estimate is conservative and should be estimated with more detail in future studies. For small, low-head hydro installations, the Electric Power Research Institute indicates the range of turbine, generator, and controls could cost $1,200 to $1,400 per kW of output. This assessment assumed a cost of $1,400/kW or $480,000 for the turbine, generator and controls. The civil infrastructure would consist of an intake, short penstock, powerhouse, and tailrace and was estimated to be 40 percent of the turbine and generator costs or $193,000. A summary of the total plant costs is shown below.
| Site Information | |
| Unit Capacity (MW) | 0.34 |
| Number of Units | 1 |
| Plant Capacity (MW) | 0.34 |
| Turbine Type | Kaplan |
| Design Head (ft) | 20 |
| Unit Speed (RPM) | 600 |
| Estimated Generation Voltage (KV) | 0.48 |
| Transmission Voltage (KV- 69,115) | 115 |
| T-Line Length (miles) | 0.10 |
| New Transformer | YES |
| Fish and Wildlife Mitigation | No |
| Recreation Mitigation | No |
| Historical & Archeological | No |
| Water Quality Monitoring | No |
| Fish Passage Required | No |
| State Sales Tax Rate ( percent) | 4.00 |
| Construction Year | 2014 |
| Total Direct Construction Cost | 995,575 |
| Civil Works | 193,436 |
| Turbine(s) | 210,455 |
| Generator(s) | 171,144 |
| Balance of Plant Mechanical | 42,091 |
| Balance of Plant Electrical | 59,901 |
| Transformer | 24,404 |
| T-Line | 20,000 |
| Contingency (20 percent) | 144,286 |
| Sales Taxes | 0 |
| Engineering and CM (15 percent) | 129,858 |
| Total Development Costs | 1,152,565 |
| Cost Escalation factor from 2010 | 1.1 |
| Licensing Cost | 50,000 |
| Total Direct Construction Cost | 1,098,929 |
| T-Line Right-of-Way | 3,636 |
| Fish & Wildlife Mitigation | 0 |
| Recreation Mitigation | 0 |
| Historical & Archeological | 0 |
| Water Quality Monitoring | 0 |
| Fish Passage | 0 |
| Annual O&M Expense | 15,508 |
| Fixed Annual O&M | 5,000 |
| Variable O&M | 5,000 |
| FERC Charges | 526 |
| Transmission / Interconnection | 1,000 |
| Insurance | 2,987 |
| Taxes | 0 |
| Management / Office / Overhead | 0 |
| Major Repairs Fund | 996 |
It was assumed a loan would be secured for the total development costs of $1,152,000. This amount was amortized at 4 percent interest over 30 years resulting in an annual loan payment of $66,620. Including annual operation and maintenance costs of $15,500, the total annual expenses were estimated to be $82,120. Irrigation districts typically are not able to subsidize hydropower projects; therefore, the revenue from power generation should nearly cash flow the project from year one of operation. For this proposed project, the energy would need to be sold at $0.10/kWh in order to cash flow the project from the first year of operation. At this rate, the project would have a simple payback period of 17.6 years.
Conclusions and Recommendations
Based on the assumptions listed above, this project does not appear to be very economically feasible. An avoided rate of $0.10/kWh is not out of the realm of possibility but is higher than current typical rates. Current avoided rates are typically around $0.04/kWh. This does not mean a more detailed analysis should not be completed. Without too much effort, more detailed flow rates can be estimated and cost estimates could be specific to the project area instead of using generalized costs. The cost index used for this analysis tends to be conservative, and actual quotes from suppliers should be used to better estimate construction costs. It is recommended to use daily average flow rates throughout a typical irrigation season and investigate whether supplemental flows can be sent through the turbine to increase energy generation. A field survey of the available head should also be completed. This information can then be used to obtain specific turbine efficiency curves, and a better estimate of plant capacity and energy generation can be completed. The following table shows the results of the preliminary analysis.
| Results – Joe Drop – Wheatland Irrigation District | ||
| Data Set | 1 | years |
| Max Head | 20 | ft |
| Min Head | 20 | ft |
| Max Flow | 240 | cfs |
| Min Flow | 80 | cfs |
| Turbine Selection Analysis | ||
| Selected Turbine Type | Kaplan | |
| Selected Design Head | 20 | ft |
| Maximum Turbine Flow | 240 | cfs |
| Generator Speed | 600 | rpm |
| Max Head Limit | 25.0 | ft |
| Min Head Limit | 13.0 | ft |
| Max Flow Limit | 240 | cfs |
| Min Flow Limit | 48 | cfs |
| Power Generation Analysis | ||
| Installed Capacity | 343 | kW |
| Plant Factor | 0.27 | |
| Projected Monthly Production: | ||
| January | 0 | MWH |
| February | 0 | MWH |
| March | 0 | MWH |
| April | 0 | MWH |
| May | 44 | MWH |
| June | 174 | MWH |
| July | 243 | MWH |
| August | 247 | MWH |
| September | 87 | MWH |
| October | 0 | MWH |
| November | 0 | MWH |
| December | 0 | MWH |
| Annual production | 795 | MWH |
| Benefit/Cost Analysis | ||
| Projected expenditure to implement project | ||
| Total Construction Cost | $ 1,152,565 | |
| Annual O&M Cost | $ 15,508 | |
| Projected Total Cost over 50-year period (present worth) | $ 1,328,691 | |
| Projected revenue after implementation of project | ||
| Power generation income for 2014 to 2060 | $ 2,936,219 | |
| Projected Total Revenue over 50- year period | $ 1,042,542 | |
| Benefit/Cost Ratio | 0.78 | |
| Internal Rate of Return | 2.8 percent | |
| Installed Cost $ per kW | $ 3,360 | |
