Final License Application
Exhibit B : Statement of Project
Operation and Resource Utilization
White Pine Pumped Storage Project
FERC Project No. 14851
White Pine Waterpower, LLC
February 2023
Final License Application – Exhibit B
List of Acronyms
4WD four-wheel drive
BESS Battery Energy Storage Systems
CAES Compressed Air Energy Storage
CAISO California Independent System Operator
CCCT combined-cycle combustion turbines
FERC Federal Energy Regulatory Commission
H head
IPP Intermountain Power Project
L length of water conveyance
PAD Pre-Application Document
PM&E protection, mitigation, and enhancement
Project White Pine Pumped Storage Project
PV solar photovoltaic solar
SCCT simple-cycle combustion turbines
WPW White Pine Waterpower, LLC
WECC Western Electricity Coordinating Council
Units of Measure
AF acre-feet
cfs cubic feet per second
gpm gallons per minute
GW gigawatt
GW-hr gigawatt-hour
MPH Miles per Hour
MW megawatt
rpm rotations per min
White Pine Pumped Storage Project February
1.0 Alternative Types of Electric Generation and Energy Storage
Carbon emissions from the U.S. power sector have dropped over 30 percent since 2005 because of a combination of a switch from coal to natural gas and an increase renewable generation (Carnegie Mellon University 2021 and 2017). Relatedly, a significant amount of continued investment in megawatts of bulk storage will be needed to support integration of carbon-free energy resources. In many parts of the western U.S., there are times of day when demand for electricity is lower than the production of renewable power. This leads to curtailment of renewable generation and negative electricity pricing. Continued deployment of renewables will require that excess power be stored for later use. To serve the needs of the entire western U.S., many gigawatt-hours of storage capacity are required.
The Project represents an exceptional grid support opportunity for Nevada and the greater region. Alternatives for carbon-free dispatchable power are limited, including primarily large-scale energy storage. Pumped storage projects have exceptional value by virtue of storage duration and lifespan. However, a relatively small number of new pumped storage sites have the unique characteristics of the Project, and no other sites in the critical market region have the combination of characteristics of the Project site.
The site for the proposed White Pine Pumped Storage Project (Project) (P-14851) is located 8 miles northeast of the City of Ely in White Pine County, Nevada. The site has a unique combination of favorable topography, access to Steptoe Valley as a water source, geologic features appropriate for tunneling to house Project facilities, and proximity to a Section 368-designated transmission corridor to an existing grid substation large enough to accommodate the Project.
Prior to selecting the proposed Project site, other electric energy alternatives were considered, including fossil-based generation, nuclear power, renewable resources (e.g., solar, wind, geothermal, hydroelectric), other pumped storage facilities, and other energy storage technologies, as discussed below.
1.1 Market Context
The future electric energy supply in the Nevada and greater regional market will come largely from solar and wind resources, which are non-dispatchable, intermittent, and variable in nature. This is evidenced by the recently voter-approved Nevada constitutional requirement for 50 percent renewable energy sourcing by 2030 and a law requiring 100 percent carbon-free resources by 2050. NV Energy has affirmed its goal for a 100 percent renewable energy future.
1.2 Fossil-Based Generation
Coal-fired steam generation provides large-scale baseload energy, serving a very different function in an energy supply portfolio than pumped storage. As a major source of greenhouse gas emissions, coal-fired generation in the market region for the Project is being phased out and there are no new plans for new coal-fired capacity additions. Therefore, coal is not a viable alternative to the Project.
Gas-fired power plants include simple-cycle combustion turbines (SCCT), combined-cycle combustion turbines (CCCT), and internal combustion reciprocating engines. Gas-fired generation has provided most of the peaking and intermediate capacity in the western market since the 1990s. CCCT plants are used for intermediate-to-baseload service. SCCTs, including frame turbines and aeroderivatives, are used for peaking power and are lower in cost than pumped storage. They, along with CCCT plants, are significant sources of greenhouse gas emissions and their inclusion in regional resource plans is being scaled back dramatically. Furthermore, while they can be used to follow variations in solar and wind output, they do not provide the energy storage function that will be critical for integrating large amounts of renewable resources. Therefore gas-fired generation is not a viable alternative to the Project.
1.3 Nuclear Power
Nuclear fission power plants have provided baseload in many regions of the U.S. since the 1970s, and several plants operate in California, Arizona, and Washington.
Nuclear power plants are a carbon-free source of generation. With the exiting technology available, they are large, have a long development timeline, and require significant capital investments. Disposal of nuclear waste is also a significant concern. There are no considerations or plans for new nuclear power in any regional resource plans for Nevada. A few small, modular reactors and natrium reactors (based on new nuclear technology) are currently proposed at sites in Idaho and Wyoming. Cost estimates for these pilot plants are high, and they will need to be operated at a close to baseload capacity factor to keep the cost of energy at a competitive level.
Nuclear generation is a baseload resource and does not provide the flexible energy storage services required to integrate large amounts of renewable energy. When combined with cost, ongoing concerns about waste disposal, and the experimental nature of new nuclear technology options, nuclear power is not a viable generation alternative to the Project.
1.4 Renewable Resources
Solar energy, particularly photovoltaic solar (PV solar), is emerging as a dominant new form of electric energy supply across the U.S., and particularly in the western U.S. and in Nevada. It is one of the lowest cost energy sources available today and does not generate greenhouse gas emissions. Solar output is relatively predictable, with only cloud cover
interrupting normal patterns of generation. However, those normal patterns involve a midday output peak, which does not coincide with peak demand, and no generation at all during the night. The result is the well-established “duck curve,” with a steep ramp needed for generating capacity that aligns with increasing load in the early evening. Since PV solar is not a firm or dispatchable generation alternative, it is not a viable alternative to the Project. In fact, for the reasons given, PV solar is a major driver of the need for energy storage resources like the proposed Project.
Wind energy is the other leading source of carbon-free energy seeing widespread deployment today. Where the wind resource is of high quality, the cost of wind energy is very low. Wind energy viability is site specific, and Nevada in general is a relatively weak wind regime as compared to other western states. Therefore, Nevada is likely to import wind energy production from other states. Furthermore, like PV solar, wind energy is not dispatchable, and it has a much lower ability than solar to predictably match demand. Like solar, therefore, the use of wind energy is a major driver of the need for energy storage resources like the proposed Project.
Geothermal energy is well-established, and Nevada has a significant number of geothermal power plants. Geothermal is carbon-free and, unlike PV solar and wind, provides firm power that is relatively dispatchable. However, the economics of geothermal power require that it operates as a baseload facility. Geothermal resources are site specific and require significant lead times and development risk. More generally, the cost of geothermal is comparatively high, and is depressing its inclusion in most resource plans. For these reasons, and since geothermal generation is generally baseload in nature and not able to provide the energy storage services needed for integrating other renewable resources, geothermal is not a viable alternative to the Project.
Conventional hydroelectric power has provided relatively firm, carbon-free energy in parts of the western U.S., specifically the Pacific Northwest, California, and Colorado, for many decades. Nevada does not have the potential for new significant conventional hydroelectric capacity due to its arid climate. Where hydroelectric power is being utilized in the state for example, at the Hoover Dam that reliance may be endangered by water shortages from climate change and other effects on the Colorado River. Across a wider region, there is some potential for new, small hydropower additions to non-powered dams, but there are no plans for major hydropower projects akin to those developed in other parts of the west in earlier generations.
The lack of viable development opportunities for new major hydroelectric power sources in the western region, along with the other reasons given here, mean that conventional hydroelectric power is not a viable alternative to the Project
1.5 Other Energy Storage Technologies
Battery Energy Storage Systems (BESS) are seeing increasing deployment, primarily in the form of lithium-ion batteries paired with PV solar. The cost of batteries has fallen significantly over the past several years, and costs are forecasted to continue to decline. Stand-alone battery projects are being constructed at the scale of hundreds of megawatts,
and projects of 1 gigawatt have been proposed. These systems generally have storage durations of 2 to 4 hours.
Like pumped storage projects, BESS represent dispatchable capacity that helps to integrate carbon-free renewable resources and will thus see significant deployment across the market. NV Energy’s resource planning indicates planned deployments of thousands of megawatts of battery systems. Compared with pumped storage, BESS have the advantage of shorter development times, modularity, and flexibility of location. However, BESS have substantial disadvantages compared to pumped storage, such as:
• Higher cost at longer durations of storage (longer duration will be increasingly important as renewable energy penetration increases);
• Significantly shorter useful life (10-20 years, depending on cycling);
• Degradation of storage capacity and efficiency through use (resulting in a higher fixed operations and maintenance [O&M] cost for augmentation);
• Environmental impacts from mining of battery materials and the lack of methods for recycling spent battery cells; and
• Future supply risks associated with competition for materials (lithium and other materials) and political considerations (e.g., reliance on raw materials and manufacturing in China). Evidence of this risk is seen in recent industry studies showing a slowdown in battery price decline due to rising commodity prices and reduced production.
Using lithium-ion as a benchmark for comparison, an analysis (Estimated Value of Project Power) is provided in Exhibit D to illustrate how and why the Project represents a lower long-term cost for long-duration storage than utility-scale batteries when viewed through the energy or MWh lens.
Other energy storage technologies, such as new battery technologies, hydrogen-based systems, and mechanical systems like rail energy storage and systems that lift and lower concrete blocks, are generally only at the demonstration or research and development stage, and do not represent commercially available alternatives to the Project.
Compressed Air Energy Storage (CAES) is the only other long-duration energy storage technology with an established track record, but this technology requires very specific and rare salt dome geology. The CAES technology available today also requires some combustion of natural gas, a source of greenhouse gases. A CAES project in Utah is being developed for the only known “Gulf Coast” style domal-quality salt formation in the western United States. There are no known proposals for CAES projects in Nevada.
1.6 Other Pumped Storage Projects
The viability of pumped storage projects requires a relatively rare combination of factors to be present, including suitable topography and geology, land availability, a source of fill water, an acceptable level of environmental impact, correct sizing for the market, and interconnection options. No major projects have been constructed in the U.S. since 1995, and relatively few proposed pumped storage projects advance to development and
receiving a FERC license. There are only three projects in the Western Electricity Coordinating Council region that have received a FERC license: Eagle Mountain in California, Swan Lake North in Oregon, and Gordon Butte in Montana. Construction has not commenced at any of these projects.
In addition, several projects have been recently proposed in Nevada specifically, via preliminary permit applications filed with the FERC. Pumped storage projects at the preliminary permit stage are considered speculative and, as of the time of this writing, none of these concepts have advanced beyond this early phase.
No pumped storage projects are currently proposed in Nevada with an equivalent or superior level of viability as that represented by the Project, based on the factors listed above, and none have advanced in terms of fundamental milestones to the extent of the Project.
1.7 Summary
BESS are the most likely alternative to the Project in terms of addressing utility and market needs for a distributed storage solution in the emerging low-carbon market. However, the advantages of pumped storage, where it can be built, make the Project an exceptional opportunity for meeting the needs of Nevada and the greater regional energy market.
There are currently no proposed projects that could provide the same benefit to optimizing regional diversity of renewable energy siting and existing and new transmission in Nevada. Therefore, no other pumped storage projects in Nevada are considered viable alternatives to the Project.
2.0 Project Location Alternatives
As discussed in Section 1.6, pumped storage project siting is unusual among utility resource technologies because the technical and economic viability of a given project is highly dependent on an uncommon combination of factors. The most significant of these factors are depicted in Figure 2.0-1 Site locations in White Pine County were explored based upon the County’s attributes of water supply, favorable geology and topography, access to construction power, short distance to an existing high voltage transmission interconnection, and local infrastructure to support multi-year construction duration. As detailed in this section, when screening for these factors, the Steptoe Valley area north of Ely became the area of focus for the Project.
2.1 Initial Geographic and Environmental Considerations
2.1.1 Topography, Water, Services, and Site Access Factors
The single greatest driver of pumped storage cost is the combination of available head (i.e., vertical drop) and horizontal water conveyance length in conjunction with suitable geology, and reservoir topography. Head can range from the low hundreds of feet to over 3,000 feet, but the optimal head for a pumped storage project with good economy of scale is 2,000 to 2,200 feet. This makes the most efficient use of water and land while minimizing the sizing of tunnels, rotating equipment, the powerhouse, and other structures. The horizontal length of the water conveyances (typically tunnels) to create the head available by the topography must typically be less than 10 to 12 times the total head for an economic project. And the geologic characteristics must be able to support economic tunneling methods and reduced underground risk. Lastly, the topography that will define the upper and lower reservoir configurations must be able to economically design and construct dams that provide enough water volume to support a minimum of 8 hours of storage at the desired capacity for generation and pumping.
Additional favorable factors present in the Steptoe Valley north of Ely include:
• A groundwater resource with a significant amount of water rights previously granted for economic development/industrial use, with a public water rights holder willing to lease a portion of those water rights for the initial fill of the Project and to grant an option to purchase a small portion of those water rights for long-term, make-up water at the Project.
• The largest town in the region, affording services needed to support Project development, construction, and operation.
• Good highway access into the Project site
2.1.2 Environmental Factors
Environmental screening factors are key to site selection. These include biological and cultural factors, along with general land use policy.
Figure 2.1-1 shows the location of the proposed Project configuration. Most of the Project Footprint falls within one or more sensitive areas or habitat classifications (i.e., Greater Sage-grouse general habitat, Greater Sage-grouse priority habitat, and U.S. Forest Service [USFS] roadless areas). Each Project configuration alternative considered has the potential to impact (temporarily or permanently) habitat, wildlife, and botanical species during Project construction and operation.
As described in Exhibit E, Section 2.2.4, a combination of protection, mitigation, and enhancement (PM&E) measures support selection of pumped storage development in this location
Final License Application – Exhibit B
2.2 Transmission Interconnection Alternatives
Beginning with location on the transmission system, and within the market, Figure 2.2-1 illustrates why the eastern Nevada region, namely in terms of transmission facilities around the Robinson Summit Substation, is a particularly important one for pumped storage development in general and the Project in particular. Nevada has adopted a clean energy mandate of 50 percent sourcing by 2030 and 100 percent by 2050. This means a high reliance on solar and potentially also wind resources, which are variable and intermittent in nature. Reliability and economic use of transmission requires energy storage, and pumped storage can be an exceptional value in energy storage Within Nevada, eastern Nevada represents an important crossroads of existing, planned, and proposed transmission:
• One Nevada (ON Line) (Figure 2.2-1) is a 500-kV transmission line already in place.
• Greenlink North and West, both of which are 525-kV transmission lines, have been approved to facilitate transmission of renewable resources and effective service to the state.
• The SWIP North Line, a 500-kV transmission line that is almost fully permitted, would connect Robinson Summit Substation to the Pacific Northwest market and open a path to the California Independent System Operator (CAISO) market, likely delivering resource diversity (in the form of wind energy) to the Nevada market, which further enhances the value of a pumped storage project in this area.
• The proposed Cross-Tie 500-kV Transmission Line would create a strong link between the Nevada and Utah systems.
• Finally, an existing Section 368-designated transmission corridor to Robinson Summit Substation that already serves two existing lines, one of which is a 345kV transmission line of similar structure to that proposed for the Project.
Three potential grid interconnection points (Gonder, Intermountain Power Project [IPP], and Robinson Summit Substation) were evaluated as potential locations for interconnecting the Project to the grid, based on the routing of existing high voltage transmission lines in the vicinity of the proposed Project. These potential Project interconnections are described below, with identification of the preferred interconnection site at the Robinson Substation.
2.2.1 Interconnection at Gonder Substation
The Project is located adjacent to the Gonder Substation, which has a 230-kV and a 345kV transmission system interconnection. Gonder Substation is the point of interconnection identified in the initial preliminary permits for the Project. In 2019, WPW engaged Power Engineers, Inc. to review the viability of interconnecting 1,000, 750, and 600 MW at Gonder Substation and at the nearby Robinson Summit Substation under N-1 conditions and utilizing the Western Electricity Coordinating Council’s 2029 Heavy Summer Base Case. The Gonder Substation interconnection alternative study indicated multiple thermal, voltage, and stability violations, even at the smallest conceptual capacity of 600 MW.
The Robinson Summit Substation interconnection was shown to be substantially better electrically from a power flow perspective and incurring significantly fewer interconnection issues. Based on the Project size, interconnection into the Gonder Substation was eliminated as a viable alternative.
2.2.2 Interconnection at IPP (Utah)
The Intermountain Power Project (IPP) is a thermal power station located in Millard County, Utah that has a 500-kV substation that is the origination point of the Southern Transmission System DC line, which delivers energy from the IPP to Southern California. This point of interconnection would presumably be strong enough to serve the Project. Presently, a 230-kV transmission line runs from the Gonder Substation, adjacent to the Project site, to the IPP. The capacity of this existing line is too small for a viable interconnection to IPP for the Project. Given that there is an existing corridor, an alternative generation interconnection line to the IPP following this path was considered. However, at least two factors make such an alternative non-viable:
1. Interconnection to the IPP would involve construction of a transmission line approximately 144 miles in length or six times greater than the distance of the proposed transmission interconnection line for the Project to Robinson Summit Substation as noted below. The greater distance would add at least $250 million to the cost of the Project, as well as incur greater transmission losses.
2. There is a large amount of generation already queued for interconnection at the IPP. WPW was able to secure an early queue position and subsequent interconnection agreement into Robinson Summit Substation that would not be possible to replicate at the IPP
2.2.3 Preferred Interconnection Alternative
The Robinson Summit Substation is the only technically and economically viable point of interconnection for the Project. It is the northern terminus of an existing 500-kV transmission line leading to the Las Vegas area, and it will be a terminus for the new Greenlink North 525-kV Transmission Line that has been approved by the Nevada Public Utilities Commission. It would also be the southern terminus for the proposed 500-kV SWIP North Transmission Line. Additionally, WPW has a signed interconnection agreement with NV Energy for this location. Through Robinson Summit Substation, the Project will help integrate renewable energy and optimize transmission utilization on a statewide and regional basis. Robinson Summit Substation is also accessible from the Project via an existing Section 368-designated transmission corridor where two lines have already been constructed.
For these reasons, Robinson Summit Substation is the preferred and proposed interconnection point for the Project. This determination has established the proposed transmission line route.
3.0 Project Siting Details
The above factors result in the selection of the Steptoe Valley north of Ely as the general location for the proposed Project.
3.1 Site Topography Alternatives
WPW examined in detail the topography of this general locale. The available head (difference in elevation) and horizontal distance between the specific location of the two reservoirs are critical factors. Figure 3.1-1 illustrates the topography alternatives analyzed.
As a result of a review of the above topographical information, seven alternative water conveyance routes within the Steptoe Valley area of White Pine County were identified as shown in Figure 3.1-2, and their individual topographical characteristics are summarized in Table 3.1-1.
Table 3.1-1. Topographical Site Alternative Characteristics
* L = total length of conveyance; H = gross rated head available for energy production
Alternative 5 was selected for advancement to the next phase of study based on having shortest tunnel length, the lowest length-to-head ratio, proximity to both construction power and the transmission interconnect, and the anticipated least cost upper reservoir arrangement. It was also recognized that the preferred upper reservoir site would result in less construction time, disturbance, and noise at the upper reservoir, which would result in fewer impacts (relative to the other alternatives) to wildlife habitat, such as Greater Sagegrouse and big game species.
3.2 Project Scale and Sizing Alternatives
The cost per megawatt and per megawatt-hour of pumped storage projects is crucial for successful project development. Generally, the larger the project, the better the economics. However, a variety of factors limit project scale and size. These include site features and constructability, environmental considerations, the availability of water, transmission capacity, and market need.
3.2.1 Reconnaissance and Pre-Feasibility Engineering
A variety of capacity sizes were considered for the Project based on the Alternative 5 site. The initial (2010) preliminary permit application proposed a 300 MW project. The successive preliminary permit application (2013) proposed a 750 MW project. The 2017 preliminary permit application included both a 250 MW and a 500 MW alternative.
After the site for the Project was selected, a reconnaissance-level engineering study was performed to assess the viability of three alternative Project configurations (HDR 2019):
1. Alternative 5.1, a 500 MW (2 x 250 MW variable speed units) pumped storage facility with an 8-hour maximum operating time.
2. Alternative 5.2, a 750 MW (3 x 250 MW variable speed units) pumped storage facility with an 8-hour maximum operating time.
3. Alternative 5.3, a 1,000 MW (4 x 250 MW variable speed units) pumped storage facility with a 6-hour maximum operating time.
Two different reservoir configurations were considered for these Project configurations: one for the 500 MW concept, and another for the 750 MW and 1,000 MW concepts. Both the upper and lower reservoirs were proposed to be earthen embankments for all three alternative Project configurations. The differences between the 750 MW and 1,000 MW concepts were primarily related to the configuration and sizing of the conveyance system. Additionally, as part of the reconnaissance study, a review of the regional and site geology was performed to identify challenges to the Project’s development due to geologic conditions. No geologic condition identified was significant enough to deem the proposed Project infeasible. Figure 3.2-1 shows the plan view of the reconnaissance study’s layout for the 750 MW and 1,000 MW concepts (HDR 2019).
During project assessments in 2019 and 2020, a capacity of 750 MW was determined to capture improved economy of scale as compared to the previously identified capacity alternatives in the prior FERC preliminary permits. However, subsequent market analyses and feedback indicated that the market is sufficiently robust for a 1,000-MW project, and the Alternative 5 site topography supported a project of that size. Engineering studies confirmed that increasing the Project size to 1,000 MW would offer greater efficiencies and improved economics. Subsequent water sourcing agreements and interconnection studies confirmed that it is feasible to develop a 1,000-MW project, which is the scale currently proposed.
Alternative 5.22 from the reconnaissance study was selected for further development during the pre-feasibility phase with the change of increasing the installed capacity to 1,000 MW and increasing the size of the units (three 333-MW variable-speed units). The Project design characteristics were further refined when initiating the formal licensing process with submittal of the PAD and NOI to FERC on May 15, 2020. The Project as outlined in the PAD was described as a 1,000-MW pumped storage facility with an 8-hour maximum operating time. A pre-feasibility study was ongoing when preparing the PAD and was completed shortly after submittal of the PAD.
As shown in Figure 3.2-2, the pre-feasibility study design modified the geometry of the lower reservoir and relocated it to be farther upslope to minimize tunneling in alluvium, reducing project head from the original configuration proposed in the reconnaissance study. This modification proposed a realignment of a 5-mile section of the Nevada Northern Railway rail line
The pre-feasibility study assumed water supply for the Project to be a new wellfield located in the Steptoe Valley approximately 12 miles north of the Project.
3.2.2 Selected Alternative Site Refinements
After the pre-feasibility study was completed, WPW commenced a feasibility study for the Project, the first stage of which was a confidential Value Planning exercise that consisted of a facilitated expert panel study of the pre-feasibility study Project configuration.
As an early step in the Value Planning exercise, the location of the lower reservoir conceived in the pre-feasibility study (Figure 3.2-2) was eliminated from further consideration. Two other lower reservoir locations were examined during the Value Planning exercise, both avoided placing the lower reservoir and its retaining dam over a known fault trace, increased head from the pre-feasibility study configuration, and avoided impact to rail line alignment (Figure 3.2-3). The more westerly of the two locations depicted in Figure 3.2-3 would necessitate utilizing two-stage pump-turbine technology, causing a significant cost increase, and therefore this alternative lower reservoir location was rejected.
The selected lower reservoir location shown in Figure 3.2-3 is the preferred Project alignment. Further description of the Project configuration and features is provided in Exhibit A Section 2.0.
Using the selected lower reservoir location, the planning process advanced several optimizations compared to the pre-feasibility configuration. The alternative optimizations considered various numbers of units, sizes of units, and fixed vs. variable speed technology.
While fixed speed units proved to be the least cost and shortest schedule option, the variable speed technology was identified as more capable of supporting potential market conditions in a low carbon future. This is due to the ability of variable speed pump-turbines to provide load following and frequency regulation services during the pumping mode in times of excess renewable energy generation.
The following improvements to further enhance efficiency also emerged from the value planning study:
• The lower reservoir location was sited to optimize Project head and avoid the need to realign the Nevada Northern Railway rail line. The selected location also avoided placing the lower reservoir and its retaining dam over a known fault trace.
• The water conveyance system was resized and reconfigured with the powerhouse complex being moved closer to the upper reservoir. This moved the powerhouse complex away from a geologic boundary between rock formations.
• The upper reservoir dam was changed from an earthen, lined embankment dam to a lined rockfill dam to utilize locally excavated materials.
• As detailed further in Section 3.3 below, the water supply conduit and water supply source were relocated closer to the lower reservoir. The proposed supply of water is now a wellfield south of the Project with four wells producing 3,000 gallons per minute (gpm) (three wells producing 1,000 gpm and one well available as redundancy) to the lower reservoir.
The selected Project configuration includes an upper and lower reservoir interconnected with a single water conveyance system along with an underground powerhouse and associated generation, pumping, and transmission equipment. Figure 3.2-4 shows the Project basic arrangement and profile. Further description of the Project configuration and features is provided in Exhibit A; and Exhibit F presents a 64-sheet drawing set of the selected Project preliminary design.
3.3 Initial Fill and Make-up Water Sourcing and Delivery Alternatives
Another site refinement resulting from the Value Planning exercise was relocation of the proposed water supply source and its associated conduit to the lower reservoir from approximately 12 miles north of the lower reservoir to a proposed wellfield closer to the lower reservoir.
Groundwater rights held by White Pine County for industrial purposes were originally permitted for diversion and use 12 miles north of the proposed lower reservoir location. The original alternative for water sourcing and delivery for the Project was to construct additional wells in the previously designated locations and construct a pipeline and associated pumps to deliver water the Project site. This alternative would entail a significant cost and additional disturbance associated with the Project.
Following further review of the area hydrogeology, WPW determined that the preferred alternative would be to change the point of diversion for the water needed for the Project to a location closer to the lower reservoir site. This would afford significant cost savings and reduce the Project Footprint. WPW filed for a change application with the Nevada Division of Water Resources (i.e., State Engineer) to move the point(s) of diversion and place(s) of use for water right Permit Nos. 72729 and 72728. The State Engineer approved the change applications and issued new water Permit Nos. 91444 and 91445 on September 22, 2022. WPW will provide proofs of completion (i.e., evidence of completed construction) and proofs of beneficial use (i.e., evidence the water has been put to beneficial use) within the time frames allowed by the State Engineer. Following the results of the future hydrogeological studies, WPW anticipates moving forward with drilling the groundwater wells in furtherance of completing the water right permitting process.
3.4 Project Road Access
The Upper Reservoir Access Road is proposed to run along the western side of the Duck Creek Range, in the Steptoe Valley, and south of the main Project features. This route has a total length of approximately 7 (seven) miles which connects from US 93 to the Upper Reservoir.
A total of 4 (four) alternative routes were analyzed against the following criteria to select the optimal route with the minimum total impacts: Total footprint / length, avoidance of Greater Sage Grouse - Primary Habitat Management Areas (PHMA), impact to private or USFS property and perceived visual impact from Ely, the NNRY, or other points in the Steptoe Valley. Criteria used in the development of these alternatives included limiting the speed to 25 miles per hour (MPH), providing a roadway width of 28 feet, minimizing switchbacks, utilizing a maximum slope of 10 percent, and the provision of rest areas (flat grades) at regular intervals. The selected Upper Reservoir Access Road was able to maintain the criteria outlined above with no significant switchbacks, avoiding Sage Grouse PHMA, and staying within BLM lands. This option is now included in Exhibit F, Drawing F803.
Alternatively, the Upper Reservoir Optional Access Road is proposed for access from the Duck Creek road on the eastern side of the Duck Creek Range for emergency use, as needed. This optional access route is approximately 3.5 miles in length and traverses both private and public lands.
4.0 Project Operation
4.1 Proposed Project Operation
The Project will be operated as an energy storage facility. At the initiation of the Project’s cycle, approximately 4,082 AF of water will be pumped from the lower reservoir through the water conveyance system and powerhouse to the upper reservoir. To generate power, water will be released from the upper reservoir and passed through the underground powerhouse containing three 333 MW, variable speed, reversible pump-turbine units. The Project is designed to generate for 8 hours at peak energy demand at a nominal 1,000 MW. The full pumping cycle to recharge the upper reservoir is estimated to be about 10.5 hours. Actual generating and pumping operations for the Project will be determined based on market demand and grid condition.
4.2 Initial Fill
Prior to the start of commercial operations, the lower reservoir must be filled with a sufficient volume of water required for equipment commissioning and normal operations. The water supply for the Project will be a wellfield near the lower reservoir. Initially filling the Project will require approximately 5,000 AF of water, equal to the sum of active storage (4,082 AF); dead storage for the upper and lower reservoirs (176 AF and 159 AF, respectively); volume of the conveyance system (120 AF); and estimated net losses (approximately 240 to 560 AF) due to precipitation, evaporation, and leakage over the filling period. The initial fill will be completed over a period of approximately 12 to 18 months at a fill rate of 3,000 gpm (6.68 cubic feet per second [cfs]).
Initial fill for the Project is anticipated to be sourced from groundwater under water rights (permits) held by White Pine County. The County’s water rights allow for diversion and industrial use of up to 20,000 AF per year, which substantially exceeds the one-time fill requirement for the Project. Under White Pine County Resolution No. 2019-40 (August 14, 2019), the County initially approved making water available subject to future approval, which was granted under Resolution No. 2021-12 (February 24, 2021) wherein the Board of County Commissioners voted to enter into a Water Use and Option to Purchase Agreement to supply all fill and make-up water for the Project. Four new wells, each with a pumping capacity of 1,000 gpm, will be installed to provide the ability to divert the groundwater for the initial fill and make-up water. The fourth well will be used to provide redundancy in the event of unanticipated equipment failures during the initial fill. A conveyance pipe will connect the lower reservoir to the well system. A fifth well of lower capacity will be installed next to the upper reservoir to supply water for construction and maintenance.
4.3 Make-up Water
Annually, WPW expects more evaporation than precipitation at the Project site; hence, WPW expects there will be a net loss of water from the Project each year. This may range from 140 AF to 520 AF per year, with an average net loss to the atmosphere of 360 AF per year. It is anticipated that approximately 100 AF per year may be lost to seepage from the lined reservoirs and 100 AF per year may be lost to leakage from the pressurized tunnels, for an estimated total of 560 AF of replacement water needed in an average year to replenish water. Maximum annual water loss is not expected to exceed 720 AF.
Anticipated make-up water needs will be sourced from the previously mentioned water rights appurtenant to the Project. White Pine County has optioned a 750 AF portion of one of the leased water rights for purchase by WPW to be used to supply all make-up water needs.
4.4 Facility Operation
The Project will be configured for fully automated operation including systems to initiate pump/turbine shutdown The Project is also proposed to be staffed with on-site operations personnel who will be able to monitor and maintain automatic systems and reduce response times for manual intervention or inspection A control room will be located in the powerhouse cavern.
With modern controls, operation will be possible at each unit control board, from the plant control room, or remotely as determined by WPW.
4.5 Annual Plant Factor
The Project is designed to generate for 8 hours each day at maximum generating capacity. Actual run times of the Project will depend on grid conditions and market demands. It is projected that the annual electrical energy production of the Project will be 2,400 gigawatthours (GW-hr), assuming the Project is in generating mode for 8 hours at maximum capacity 6 days per week, 50 weeks per year. This yields an annual plant factor of 27 percent. It is anticipated that the units will be connected to the grid for over 20 hours a day in either generating, pumping, or condensing operating modes.
4.6 Operations during Adverse, Mean, and High Water Years
FERC defines a closed-loop pumped storage project as a project that utilizes reservoirs situated at locations other than natural waterways, lakes, wetlands, and other natural surface water features, and may rely on temporary withdrawals from surface waters or groundwater for the sole purpose of initial fill or the periodic recharge needed for project operation
The Project meets the FERC definition of a closed-loop pumped storage project as it is not located on a natural waterway, lake, wetland or other natural surface water feature and Project operations will not be affected during adverse, mean and high water years
After initial fill, the Project will maintain a volume of water (usable volume of water) that is cycled between the upper and lower reservoirs without the need to add water, except to make up for leakage, seepage, and evaporation losses.
4.6.1 Initial Fill During Adverse Water Year
As noted in Section 4.2, initial fill of the Project will require approximately 5,000 AF of water, anticipated to be pumped from groundwater leased from White Pine County pursuant to a water supply agreement. These water rights have a priority date of 6/16/1978. Initial fill is scheduled to occur over a period of 12 to 18 months. Based on available information, WPW anticipates access to sufficient groundwater volume for initial fill under the water supply agreement with White Pine County. If the scheduled initial fill coincides with an extended period of very low groundwater replenishment, it is possible that the Project’s access to groundwater for initial fill could be curtailed by order of the Nevada State Engineer based on water right priorities. Under this scenario, initial fill would be re-scheduled for a time not constrained by Nevada State Engineer curtailment.
4.6.2 Routine Project Operations During Adverse Water Years
Routine Project operations will consist of moving a specific volume of water back and forth between the upper and lower reservoirs as dictated by generation and pumping dispatch schedules. As long as this volume is sustained, Project generation capabilities will be preserved. WPW estimates that, on average, approximately 560 AF will be needed annually to make up for losses to seepage, leakage, and evaporation.
During most years, it is not expected that any reductions in usable storage will occur at the Project. There will be sufficient groundwater available for make-up water to maintain the total active storage volume of water for the normal pumping and generating cycle of operations. Similarly, during extended periods of high groundwater replenishment, sufficient groundwater will be available for Project make-up water.
During extended periods of very low groundwater replenishment, it is possible that the Project’s use of groundwater could be curtailed by order of the Nevada State Engineer. Under this scenario, the ability of the Project to make up losses in the volume of water retained in the reservoirs will depend upon Nevada State Engineer curtailment orders and water right priorities.
5.0 Dependable Project Capacity and Energy Production
The Project’s capacity is estimated to be a nominal of 1,000 MW for 8 hours a day. Actual run time of the Project will be dependent on grid conditions and market demand. Annual electrical energy production will be 2,400 GW-hr assuming the Project runs at full generation capacity for the maximum 8 hours each day, 6 days per week, 50 weeks per year.
5.1 Project Flow Data
The Project is an off-stream, closed-loop, pumped storage facility and not hydrologically connected to any surface or subsurface waters. Therefore, there is no flow data available in relation to the Project.
5.2 Reservoirs
5.2.1 Upper Reservoir
At the proposed maximum normal operation pool elevation of 8,605 feet, the upper reservoir has an active storage capacity of 4,082 AF and a surface area of approximately 46.8 acres. The proposed minimum operating elevation of 8,490 feet will submerge the intake sill by over 40 feet to avoid vortex formation. An elevation capacity curve for the upper reservoir is provided in Figure 5.2-1.
5.2.2 Lower Reservoir
At the proposed maximum normal operation pool elevation of 6,435 feet, the lower reservoir has a total storage capacity of 4,241 AF and an active storage capacity of 4,082 AF and a surface area of approximately 62.8 acres. The proposed minimum pool elevation of 6,355 feet will submerge the top of the intake/outlet structure by approximately 24 feet and submerge the bottom of the intake/outlet structure by approximately 55 feet. An elevation capacity curve for the lower reservoir is provided in Figure 5.2-2
5.3 Project Flow Range
The Project will have an estimated maximum operating flow rate in the generating mode of approximately 6,457.3 cfs at maximum hydraulic capacity with all three 333 MW, variable speed turbine units operating at rated output during the lowest head condition and 5,400 cfs at full pumping capacity. The Project’s estimated design flow range will be determined after turbine and reservoir configurations have been finalized.
5.4 Tailwater Rating Curve
As the Project is an off-stream, closed-loop, pumped storage facility, there is no tailwater rating curve. The tailrace tunnel and lower reservoir will serve as the Project’s tailwater. The tailwater elevation will increase as a function of reservoir volume instead of flow.
5.5 Project Capability versus Head
The Project is designed to provide a nominal 1,000 MW of capacity. As water is released from the upper reservoir into the lower reservoir, the head between the two reservoirs
decreases; the changing head impacts the maximum generation level achievable. Maximum gross head will occur when the upper reservoir is at its maximum operating elevation and the lower reservoir is at its minimum operating elevation. The minimum gross head will occur in the opposite case, where the upper reservoir is at its minimum operation elevation and the lower reservoir is at its maximum operating elevation.
6.0 Regional Power Needs and Use of Project Power
The regional transmission grid has a growing need to integrate wind and solar energy generation sources and to provide a full range of supportive services to ensure a reliable and resilient transmission grid. The Project would help address these needs. The Applicant is an independent power producer developing a single project for grid interconnection and is not responsible for system or regional planning needs. Power absorbed during the pumping mode will come from the wholesale energy market and will be purchased when the energy system is imbalanced and in surplus. Power produced during the generating mode will be delivered to the wholesale market to satisfy peak demand periods. If the Project operates for one cycle per day, 6 days a week, 50 weeks a year, the generated energy will be 2,400 GW-hr per year. Assuming 76.6 percent efficiency, the plant will need 3,133 GW-hr of pumping power per year. It will later be determined how much power per year will be needed for daily operations.
7.0 Future Development Plans
The Project is a proposed new development and is presented as such in this license application. At this time, WPW has no plans for additional, future development at the Project.
8.0 Citations
Carnegie Mellon University, Scott Institute for Energy Innovation. 2017. Power Sector Carbon Index Dropped 24% from 2005-2016. Accessed January 17, 2022: Power Sector Carbon Index dropped 24%… | CMU Power Sector Carbon Index (emissionsindex.org)
____. 2021. Power Sector Carbon Index – 2021 Q2 Update. Accessed January 17, 2022: Power Sector Carbon Index – 2021 Q2… | CMU Power Sector Carbon Index (emissionsindex.org)
Gridflex Energy, LLC. 2017. Preliminary Permit Application for the White Pine Pumped Storage Project. July 12, 2017.
HDR. 2019. White Pine Pumped Storage Project Reconnaissance Study. Prepared for White Pine Waterpower, LLC. June 6, 2019.
Final License Application – Exhibit B
White Pine Pumped Storage Project
_____. 2020. White Pine Pumped Storage Project Pre-Feasibility Study. Prepared for White Pine Waterpower, LLC. August 5, 2020.
NV Energy. 2020. Greenlink Nevada. Online [URL]: https://lands.nv.gov/uploads/meeting_minutes/E2021-098.pdf
White Pine County. 2019. Resolution No. 2019-40.
_____. 2021. Resolution No. 2021-12.
White Pine Waterpower, LLC, 2010. Preliminary Permit Application for the White Pine Pumped Storage Project. April 6, 2010.
_____. 2013. Preliminary Permit Application for the White Pine Pumped Storage Project. September 2013.
2020. Pre-Application Document and Notice of Intent for the White Pine Pumped Storage Project (FERC Project No. 14851). May 15, 2020.
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