Does a PV Tracking System Make Sense for Co-ops?

Transcription

1 Does a PV Tracking System Make Sense for Co-ops? An analysis of the value of off-azimuth arrays and single-axis tracking on peak demand matching for electric distribution co-ops Douglas R. Danley Business and Technology Strategies National Rural Electric Cooperative Association Arlington, VA doug.danley-contractor@nreca.coop Abstract Most utility-scale PV systems are designed to optimize annual energy output. This is especially true with power purchase agreements (PPAs) which focus entirely on the total cost of energy. Utilities, however, value energy differently, depending on the time of day. For example, utilities are often subject to demand charges based on peak usage which often occur during the afternoon on hot summer days. Solar that provides power during that peak would thus provide more value than at other times. This paper evaluates the system performance of off-azimuth designs (facing southwest and west) and single axis tracking compared with optimum due south orientation, with an eye on performance during afternoon peak periods. A discussion of the potential economic benefits is provided, along with a sample economic analysis of the differential value of array options. The results show that off-azimuth systems can provide significant demand reduction benefits with a penalty of reduced annual energy production. Tracking systems can provide both increased energy and further demand reduction for afternoon peaks typical of distribution cooperatives. Economic benefits are highly dependent on both the location and the procurement rate structure of a particular co-op. Index Terms photovoltaic systems, orientation, azimuth, tracking, peak demand, electric co-op I. INTRODUCTION Most utility-scale PV systems are designed to optimize annual energy output. This is especially true with power purchase agreements (PPAs) which focus entirely on the total cost of energy. Utilities, however, value energy differently, depending on the time of day. For example, a distribution utility usually pays a both a supplier demand charge and a transmission congestion charge based on its usage during a peak period, often in the afternoon of a hot summer day. A single period ranging from 15 minutes to an hour can determine the peak charges for the month, and in some cases four months of peaking determine the demand charges for an entire year. There are a number of options which utilities can use to use PV systems to help reduce peak-based charges. First, the array could be aimed off-azimuth, facing towards the west. This provides more power during the afternoon period (which is typically more of a peak than the morning) with the penalty that the system produces somewhat less energy overall than an optimized system facing due south. Second, the system could use a tracking system to keep the array aimed more closely towards the sun compared with a fixed system. This type of system broadens the shoulders of the array output, providing more power both during the morning hours and the evening hours. This involves both extra capital costs (due to the tracking structures) and extra maintenance costs (since things that move will inevitably need more maintenance than things that don t). The third method is to use energy storage to collect excess energy during the day and discharge during peak periods to reduce the overall system demand. This paper focuses on the solar-only options, leaving the energy storage analysis to a separate discussion. The analysis is done using PVSyst software ( to model system performance of an array with four options fixed tilt facing due south, fixed facing southwest, fixed facing west and single axis tracking, which is the most common and cost effective type of tracking system for utility-scale PV systems. In particular, the analysis looks at the increase in production during afternoon hours in the summer months, which is the typical time which determines monthly and annual demand charges for distribution utilities. II. REFERENCE SYSTEM DESIGN AND ARRAY STRUCTURE OPTIONS Utility-scale photovoltaic (PV) systems are typically postage stamp replications of smaller systems. For example, a ten-megawatt PV system might be made up of ten onemegawatt systems wired together into a single interconnection. Therefore, this paper uses a template one-megawatt system design as a reference, with the understanding that the results can be scaled as needed. A. Reference Design The one-megawatt ( 1MW-AC) template design was developed for the SUNDA (Solar Utility Network Pg. 1

2 Development Acceleration) project which is being undertaken by the National Rural Electric Cooperative Association (NRECA) in collaboration with the US Department of Energy (USDOE). The system consists of a 1.4 MWp-DC PV array which powers two 500 kw-ac inverters for a total system output of one megawatt AC (1 MW-AC). The array is ground mounted at a fixed tilt, the value of which is determined by the system latitude. The array faces due south for optimum annual energy production. A complete drawing set for the reference design is available for download at B. Off-Azimuth Southwest Since most utilities face peak demand in the afternoons, an obvious next step is to face the array towards the west. For this option, the design for the reference template was used, with the exception that the array faces southwest and has five degrees more tilt to better capture the lower afternoon sun. C. Off-Azimuth Due West A more dramatic step is to face the array due west and increase the tilt by ten degrees to try and squeeze as much energy as possible from the late afternoon sun. This might be a consideration if the utility peak is late in the afternoon on summer days. D. Single Axis Tracking Systems which move the array to face more closely towards the sun as it moves across the sky can offer significant performance boosts, both in annual energy production and in specific energy product earlier in the morning and later in the afternoon than traditional south-facing designs. This is balanced by the fact that tracking systems have moving parts which require maintenance, and tend to cost more than equivalent fixed tilt systems. Tracking systems work better in areas with high clearness, which is defined as the ration between extraterrestrial insolation and total direct and diffuse insolation measured on a horizontal surface on the earth. The most common tracking designs in use today rotate strings of PV modules around a horizontal north-south axes. The east-west angle is matched to the sun s position using a straight mathematical calculation. Systems use either a single motor per row or one motor to move multiple rows via an extended lever system. Tracker systems currently cost 6-10% more per kwp than fixed arrays, and also require 25-40% more land area. This analysis assumes the same electrical configuration as the template design 1.4 MWp-DC / 1 MW-AC. III. ANNUAL SYSTEM PERFORMANCE System performance calculations used PVSyst modeling software ( with backup calculations using NSolVx ( PVSyst uses Typical Meteorological Year (TMY) one-hour resolution data files to provide input data for global horizontal insolation (GHI) and ambient temperature. Output includes hourly system performance which is useful for evaluating specific afternoon performance. NSolVx uses monthly average GHI data (ref. NREL s Solar Radiation Data Manual for Flat-Plate and Concentrating Collectors ) with output expressed as AC energy per month. This allows rapid calculation of monthly and annual energy output for different sites and different array configurations. The performance analysis for this paper was done using data for Dodge City, Kansas (latitude 37.8 ), home to Victory Electric Cooperative. This site was chosen to be representative of the wide variety of locations of US electric co-ops, most of which are in locations that are not typically thought of as prime sites for solar. Dodge City has an average GHI of almost 4.9 kwh/m 2 /d, with a peak of 7.2 kwh/m 2 /d in the summer and a winter minimum of 2.4 kwh/m 2 /d. The hourly data was corrected for daylight savings time, but was not corrected for the exact longitude of the site within its time zone. The baseline system faces south with a tilt of 25. Although an optimized system might favor a slightly higher tilt, the lower tilt represents current best practice, sacrificing a slight amount of performance in order to reduce row-to-row shading by packing the array tighter into a given space. Option 1 faces southwest at a tilt of 30, and option 2 faces due west at a tilt of 35. Option 3 uses a single axis tracker with a horizontal (non-tilted) north-south axis. Figure 1 shows the annual output and July output of the various options compared with the reference design. The tracking system supplies 22% more energy than the reference design on an annual basis, but in July, it supplies nearly 40% more energy. The southwest facing system has an annual energy penalty of only 5%, while the west facing system only produces 79% of the energy of the reference design, although the penalty in July is only about 6% compared with the south-facing design. Figure 1 Comparison of Annual and July Performance of Array Configurations Figure 2 shows the monthly output of the various array configurations. The energy advantages of the tracking system and disadvantages of the west-facing system are clearly visible in this graph. Pg. 2

3 Figure 2 Monthly System Output of Array Configurations IV. PEAK MONTH PERFORMANCE As shown in Figures 1 and 2, the tracking option has a clear advantage in annual energy output, producing 22% more annual energy than the reference design and 58% more energy than the west facing array. So why would anyone consider a west facing array? To answer this, a more detailed look at the performance of a summer peak month is needed. Figure 3 shows the hourly system performance of the various array configurations on a typical clear summer day. The tracking system clearly produces the most energy later into the afternoon. However, it is interesting to note that the west facing array matches the afternoon shape of the tracking system quite closely, at the expense of producing very little energy in the morning. The southwest system maintains the same shape as the reference design, with the energy shifted about two hours into the afternoon. The afternoon benefit clearly falls to the west facing system and the tracker, but the magnitude of the benefit depends on the timing of the peak. Figure 4 shows the relative output of the array configurations at varying times in the afternoon. At 4 pm, the alternate array configurations show very little benefit over the reference design. By 5 pm, the south-facing system has fallen off by 40% while the southwest system has only fallen 10% and the other two options are maintaining full output. By 6 pm, the two best options are producing more than twice as much energy as the reference design, and by 7 pm the south facing design is down to almost nothing, while the two best options continue to produce 50% or more of rated energy. Figure 4 Afternoon system output Utility peaks tend to be closely correlated to hot days, but there is a question of whether the sample day show above is representative of a peak load day. To answer this, the performance curves for the six hottest July days were pulled out and compared. All turned out to be clear days as shown in Figure 5. Figure 3 Hourly System Output on a Clear Summer Day The orange bell-shaped curve centered around 1 pm (taking daylight savings time into account) is the south facing array. The green and yellow curves show the system performance as the array is aimed southwest and then due west. The blue curve shows the characteristic wide shoulders of a tracking system, which produced more energy earlier in the morning and later in the afternoon than a fixed array. Figure 4 System Output six hottest days in July Pg. 3

4 Note that all the configurations peak out at 1 MW-AC. This is because the DC rating of the array in the reference design is sized at 140% of the AC rating of the inverter. This allows the array to be utilized more fully during the vast majority of the year, at the expense of clipping or limiting the system output to the inverter capacity on select sunny days. Figure 5 shows the annual output of the system on an hourly basis, with a line showing the clipped output. Despite the frequent excursions over 1 MW that are evident in the graph, the total annual clipping for this system is less than 3.5%. Since a PV array degrades over time, this effect will become smaller and eventually disappear during the life of the system. Sys Output kw-ac 1,280 1,152 1, System Performance by Hour Day of Year Figure 5 Hourly System Output showing Clipping V. ECONOMIC BENEFITS OF ARRAY CONFIGURATION OPTIONS Most electric cooperatives are distribution utilities, which means that they purchase a majority of their energy from another source, typically a generation and transmission (G&T) co-op, but sometimes from a provider such as the Tennessee Valley Authority (TVA) or from the open market. There are also many examples of co-ops who purchase energy from multiple sources, which often have different rate structures. This diversity makes it impossible to do an economic analysis that would apply to all co-ops. However, there are some basic principles which can be applied to analysis of a specific co-op s benefit stream. Distribution co-op purchasing rates structures tend to be single-cost energy (no time-of-use rates) with one or more peak demand components. The most common is a coincident demand, which is the load of the co-op during the supplier s peak period, which may last 15 or 30 minutes. This is usually calculated on a month-by-month basis and there are some key indicators (such as ambient temperature), but there is no ways to know the timing of the actual peak until it happens. (One co-op analyst called this the magic half hour. ) The second type of charge is regular demand, which is the peak load of the co-operative without consideration of the supplier. A third type of charge is transmission congestion which is market-based, but is often passed along directly to the distribution co-ops. There are many other variations on these charges. One coop reported that the average of the 15-minute coincident and transmission congestion peaks during the four summer months determine the demand charges for the entire year. In other cases, the demand charges are calculated separately for each month. In general, for an afternoon peaking co-op, the coincident demand and the transmission congestion tend to peak earlier in the day than the actual co-op peak. Example: Assume that a co-op pays $20 per kw per month in demand charges, and that the coincident peak occurs at 6pm during the summer months. The reference system produces 241 MWh during July at an assumed value of $60 per MWh, so the total energy value is $14,500. Using the data from the analysis, the reference system would provide 389 kw in demand reduction during July, for a savings of $7,800 and a net benefit of just over $22K. Facing the system southwest would reduce the energy by a few percent, but increase the demand savings to over $13.5K, nearly matching the total energy value for the month. Facing the system due west would reduce the energy savings even more, but the demand savings would increase to 25% more than the energy charges and result in even greater savings. The tracking system shows the greatest benefit in both energy production and demand savings, with 75% more value than the reference system. Table 1 and Figure 6 show the comparison of benefits for this example. South 25 Southwest 30 West 35 Tracking July MWh Energy cost ($/MWh) $60 $60 $60 $60 Energy Savings $14,484 $14,196 $13,566 $20,262 Demand reduction (kw) Demand charge ($/kw) $20 $20 $20 $20 Demand Savings $7,783 $13,655 $17,104 $19,180 Total Savings $22,267 $27,851 $30,670 $39,442 Table 1 Energy and Demand Benefits using $20/kW/month demand charge Figure 6 Energy and Demand Benefits for Example 1 Assuming that the system produces an average of 90% of this level of demand savings for the four summer months and that there is no value for the rest of the year, the demand charges for the southwest-facing system are easily more valuable than the value of lost energy production. The same is true for the west facing system, although to a lesser extent. The Pg. 4

5 tracking system is the clear winner, producing total annual benefits more than 40% higher than the reference design. In a second example, transmission congestion peaks at 5 pm and the G&T coincident demand peaks at 6 pm. The charges for each on based on the 15 minute peaks for the four summer months (June, July, August, September). Transmission congestion is charged at $48 per year per kw and G&T coincident demand is charged at $96 per year per kw. Table 2 and Figure 7 show the comparison of benefits for this example. The off-azimuth options provide no extra value, while the single axis tracker shows a clear benefit. South 25 Southwest 30 West 35 Tracking July MWh Energy cost ($/MWh) $60 $60 $60 $60 Energy Savings $14,484 $14,196 $13,566 $20,262 Congestion reduction July (kw) Congestion reduction Summer (kw) Congestion Charges ($/kw/yr) $48 $48 $48 $48 Congestion Savings $28,223 $38,261 $42,646 $43,200 Demand Reduction July Demand Reduction Summer Demand Charges $96 $48 $48 $48 Demand Savings $33,621 $29,494 $36,944 $41,430 Congestion + Demand Savings $61,844 $67,755 $79,590 $84,630 Annual Energy 2,467 2,339 1,961 3,022 Annual Energy Value $148,014 $140,340 $117,648 $181,290 Total System Savings $209,858 $208,095 $197,238 $265,920 % of Reference Savings 100% 99% 94% 127% Table 2 Energy and Demand Benefits using congestion plus demand charges based on four summer months sites across the US. Annual tracker output shows a small trend towards increased output with increased clearness. Figure 8 Annual Tracker Bonus vs Annual Clearness for selected sites Figure 9 shows the tracker bonus in July for each of the same sites. This time, there are benefits across the country, regardless of annual clearness values. Figure 9 July Tracker Bonus vs Annual Clearness for selected sites Figure 7 Energy and Demand Benefits for Example 2 VI. APPLICABILITY TO OTHER SITES Tracking systems tend to work better in areas with high clearness, which is defined as the ratio between extraterrestrial insolation and total direct and diffuse insolation measured on a horizontal surface on the earth. For example, Salem, OR has an average annual clearness of 48% and a summer peak of 59%, while Tucson, AZ has an annual average clearness of 66% and a spring peak clearness of 72%. Figure 8 shows the tracker bonus versus the south-facing reference design as a function of annual clearness index for six VII. SUMMARY In summary, off-azimuth and single axis tracker systems for utility-scale PV arrays can provide additional value to distribution utilities who pay demand charges for their energy procurement. The value of these options depends both on the siting of the system and on the specific procurement rate structure of the utility in question. In the case of the tracker, the added value must be compared with the additional system cost (land, capital expense, and ongoing maintenance). ACKNOWLEDGMENTS The author would like to acknowledge Michael Smith from The Electric Cooperatives of South Carolina, Curtis Trivitt from CoServ, Shane Laws from Victory Electric Cooperative and Milton Geiger from Poudre Valley REA for helping explain the economics of demand reduction, as well as Paul Carroll and Debra Roepke from NRECA and David True from PowerSecure for their work on the SUNDA project. Pg. 5