DETAILED ACTION
Summary
This Office Action is in response to the Amendments to the Claims and Remarks filed November 26, 2025.
In view of the Amendments to the Claims filed November 26, 2025, the rejections of claims 1-6 and 8-21 under 35 U.S.C. 103 previously presented in the Office Action sent August 26, 2025 have been substantially maintained and modified only in response to the Amendments to the Claims.
Claims 1-6 and8-21 are currently pending.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The factual inquiries for establishing a background for determining obviousness under 35 U.S.C. 103 are summarized as follows:
1. Determining the scope and contents of the prior art.
2. Ascertaining the differences between the prior art and the claims at issue.
3. Resolving the level of ordinary skill in the pertinent art.
4. Considering objective evidence present in the application indicating obviousness or nonobviousness.
Claim(s) 1-6 and 8-21 is/are rejected under 35 U.S.C. 103 as being unpatentable over Morse et al. (U.S. Patent No. 10, 935,992 B1) in view of Hoff (U.S. Pub. No. 2019/0095559 A1) and Jungerman et al. (U.S. Pub. No. 2014/0070837 A1).
With regard to claims 1, 11, and 12, Morse et al. discloses a method of controlling a solar array comprising:
receiving a plurality of current and voltage values generated from each of a plurality of solar modules disposed geographically within the solar array (see line 33-38, column 4 teaching one solar module per tracker 300; see line 63, column 6 to line 17, column 7 teaching photovoltaic reference cell sensors 350 on individual trackers 300 or entire row of trackers 300 cited to provide for the claimed “receiving a plurality of current and voltage values generated from each of a plurality of solar modules disposed geographically within the solar array” because the cited photovoltaic reference cell sensors 350 corresponding to each solar module on each individual trackers 300 provides current and voltage values generated from the photovoltaic reference cell sensor 350 of each module on each tracker);
the plurality of solar modules supported by solar trackers, each solar tracker configured to position at least one solar module to a solar tracker angle (see line 33-60, column 4);
calculating a plurality of diffuse fraction irradiance (DFI) values for each of the plurality of solar modules based on the received plurality of current and voltage values generated (see line 24-38, column 6 teaching calculating a plurality of diffuse fraction irradiance (DFI) values for each of the plurality of solar modules based on the received plurality of current and voltage values generated from photovoltaic reference cell sensors 350);
defining at least two zones within the solar array based on the light conditions (see line 63, column 6 to line 17, column 7 teaching defining at least two zones, such as defining the cited photovoltaic sensor 350 for an entire row as a zone and defining another cited photovoltaic sensor 350 for another entire row as a zone based on the sensed light conditions of each sensor 350);
determining a zone-specific solar tracker angle for each of the at least two zones based on the light conditions (see line 47-56, column 6 teaching determining solar tracker angle based on light conditions from sensors 350 which would provide for a zone-specific solar tracker angle for each of the cited at least two zones based on the light conditions from each sensor 350 in each zone);
transmitting the zone-specific solar tracker angle to a computing device associate with each solar tracker in the at least two zones of the solar array (such as computing device 345, Fig. 3); and
driving the solar trackers such that the solar trackers within each zone are oriented to the zone-specific solar tracker angle for each zone (see line 33-60, column 4 teaching driving the solar trackers such that they are oriented at the solar tacker angle which would correspond to each of the cited zone-specific solar tracker angles for each zone).
Morse et al. teaches independent control designs for orienting solar modules in different zones independently (see Fig. 4 via individual sensors 350 on each row of modules in the solar array) to account for diffused irradiance from clouds or overcast (see line 24-38, column 6) but does not teach the control designs include mapping and generating a digital image to represent the diffused fraction irradiance.
However, Hoff discloses a control design for orienting solar modules to account for diffused irradiance from clouds or overcast comprising:
receiving current and voltage values generated from a plurality of solar modules of the solar array (see [0069] teaching receiving “power statistics, including a time series of the power statistics for the photovoltaic plant… The photovoltaic plant configuration specification includes power generation and location information, including direct current (“DC”) plant and photovoltaic panel ratings…voltage at point delivery”);
calculating a diffuse fraction irradiance (DFI) for the plurality of solar modules (see [0209-0210] and [0240] teaching calculating a diffuse fraction irradiance);
mapping the diffuse fraction irradiance for the plurality of solar modules (see [0069-0073] and [0287-0288] teaching mapping from calculated irradiance statistics combined with the photovoltaic fleet configuration to generate the high-speed time series photovoltaic production data and simulation with different geographical tiles);
generating a digital image of light conditions in the solar array based on the mapped diffuse fraction irradiance (see [0069-0073] and [0079] teaching “power output data 19 for a photovoltaic plant is generated using observed field conditions relating to overhead sky clearness. Solar irradiance 23 relative to prevailing based weather stations 24. Solar irradiance measurements can also be derived or inferred by the actual power output of existing photovoltaic systems 25. Additionally, satellite observations 26 can be obtained for the geographical region” and “satellite imagery data is pixel-based, the data for the geographical region is provided as a set of pixels, which span across the region and encompassing the photovoltaic fleet”);
determining a solar tracker angle based on mapped diffuse fraction irradiance (see [0069-0073], [0203-0204], and [0221-0222] teaching “tracking mode”, “shading and physical obstructions can be evaluated by specifying obstructions as part of a system’s configuration specification”, “Perform this analysis for all angles to tune for the effects of obstructions within the sun’s path”);
transmitting the solar tracker angle to a computing device associated with each solar tracker in the solar array (see [0069-0073] “computer system 21 executes the methodology described infra which can be stored or provided 27 to planners and other interested parties” and “data feeds 29a-c from the various sources of solar irradiance data”); and
driving the solar trackers such that the solar trackers are oriented to the same angle (see [0203-0204], [0221-0222], and [0226-0227] teaching “a two-step approach can be used to quantify the effect of obstructions on diffuse and direct irradiance. Combining the effect of obstructions by performing the two steps, as discussed in detail infra, results in an equivalent shading and physical obstruction profile that can be used with the system's configuration specification when forecasting photovoltaic production”, “This process will result in a profile that simultaneously modifies the obstruction angles that affect direct irradiance and adjust the angles to retain the correct overall diffuse obstructions.”, and “to improve performance through changes to the plant's operational features, such as revising tracking mode (fixed, single-axis tracking, dual-axis tracking), azimuth, tilt, row-to-row spacing, tracking rotation limit, and shading configurations. Moreover, the accuracy or degree to which a system configuration is “optimal” can be improved further by increasing the degree by which each of the configuration parameters is varied. For instance, tilt angle can be permuted in one degree increments, rather than five degrees at a time. Still other ways of structuring or permuting the configuration parameters, as well as other uses of the hypothetical photovoltaic system configurations, are possible.”).
Thus, at the time of the invention, it would have been obvious to a person to having ordinary skill in the art to have substituted the control designs for each zone of Morse et al. for the control design of Hoff because the simple substitution of a known element known in the art to perform the same function, in the instant case a control design to orient solar modules taking account for diffused light, supports a prima facie obviousness determination (see MPEP 2143 B).
Hoff teaches adjusting the received voltage and current data of the solar modules supported by the solar trackers (see [0069-0073], [0128], and [0226-0232]) but does not disclose accounting for a decrease in output that is expected to occur as a function of time for any of the plurality of solar modules.
However, Jungerman et al. teaches a method of controlling a solar array (see Abstract) and discloses accounting for a decrease in output that is expected to occur as a function of time for the solar modules (see [0002-0006] and [0038] teaching “it is desirable to monitor the performance of the solar panels to detect degradation due to aging, faults, or environmental conditions, because even minor degradation in performance of one or more solar panels can deprive the PV system of significant energy production over the long operating life of the solar panels” which is cited to provide for the claimed accounting “for a decrease in output that is expected to occur as a function of time” because Jungerman et al. teaches an expected decrease in output/energy production due to degradation as a function over time/aging and monitors the solar panels to detect and account for the degradation).
Thus, at the time of the invention, it would have been obvious to a person having ordinary skill in the art to have modified the adjusting received voltage and current data in the method of Morse et al., as modified by Hoff above, to include accounting for a decrease in output that is expected to occur as a function of time, as suggested by Jungerman et al., because it would have led to identifying a cause of significant energy production loss over the operating life of the modules.
Morse et al., as modified above, teaches the claimed calculating a plurality of DFI values using the adjusted received plurality of current and voltage values “to improve accuracy of the calculating of the plurality of DFI values” because Morse et al., as modified above, teaches adjusting the received current and voltage values to account for degradation due to aging which would improve the accuracy of the calculating of the plurality of DFI values as it accounts for degradation.
With regard to claims 2 and 13, independent claims 1 and 11 are obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses further comprising
storing the digital image of light conditions in a memory (see [0069-0073], [0079], and [0088] teaching “computer system 21 includes hardware components…memory”).
With regard to claims 3 and 14, dependent claims 2 and 13 are obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses further comprising
generating a forecast digital image of light conditions is the solar array and storing the forecast digital image of light conditions in a memory (see [0069-0073] and [0199] teaching “computer system 21 includes hardware components…memory”).
With regard to claims 4 and 15, dependent claims 3 and 14 are obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses further comprising
receiving a stored forecast digital image of light conditions; and comparing the received stored forecast digital image of light conditions to a most recent digital image of light conditions, wherein if there is a match between the received stored forecast digital image of light conditions and the most recent digital image of light conditions, each of the at least two zones defined from the stored forecast digital image of light conditions and the zone-specific solar tracker angles determined for each of the at least two zones are transmitted to the computing device associated with each solar tracker in the solar array (see [0199], [0223-0228], and [0289-0290]).
With regard to claim 5, dependent claim 4 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses wherein
if there is no match the method further comprises: defining zones within the array based on the light conditions in the most recent digital image of light conditions in the solar array; determining a zone-specific solar tracker angle for each zone based on mapped diffuse fraction irradiance in the most recent digital image of light conditions in the solar array; and transmitting the zone-specific solar tracker angle to a computing device associated with each solar tracker in the solar array (see [0199], [0223-0228], and [0289-0290]).
With regard to claim 6, dependent claim 5 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses wherein
the computing device associated with each solar tracker in the solar array is one of a self-powered controller (SPC) or a network control unit (NCU) (see [0019] and [0073]).
With regard to claim 8, independent claim 1 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses further comprising
determining one or more of direct normal irradiance (DNI), global horizontal irradiance (GHI), diffuse horizontal irradiance (DHI), any combination of these (see [0069] and [0081]).
With regard to claim 9, independent claim 1 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses further comprising
receiving one or more of a satellite images, weather forecasts, and data collected by weather stations (see [0068-0071], [0076-0081], and [0199]).
With regard to claim 10, independent claim 1 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Hoff discloses further comprising
comparing the satellite images, weather forecasts, or data collected by weather stations to one or more of the DNI, GHI, DFI, and DHI to confirm any cloudiness and near object shading (see [0068-0071], [0076-0081], [0199], and [0289]).
With regard to claims 16 and 18, Morse et al. discloses a method for controlling a solar array comprising:
receiving a plurality of current and voltage values generated from each of a plurality of solar modules disposed geographically within the solar array (see line 33-38, column 4 teaching one solar module per tracker 300; see line 63, column 6 to line 17, column 7 teaching photovoltaic reference cell sensors 350 on individual trackers 300 or entire row of trackers 300 cited to provide for the claimed “receiving a plurality of current and voltage values generated from each of a plurality of solar modules disposed geographically within the solar array” because the cited photovoltaic reference cell sensors 350 corresponding to each individual trackers 300 provides current and voltage values generated from the photovoltaic reference cell sensor 350 of each tracker);
the plurality of solar modules supported by solar trackers, each solar tracker configured to position a row solar module to a solar tracker angle (see line 33-60, column 4 teaching rotation mechanism 310 capable of positioning an entire row of tracker panels);
calculating a plurality of diffuse fraction irradiance (DFI) values from the received plurality of current and voltage values generated (see line 24-38, column 6 teaching calculating a plurality of diffuse fraction irradiance (DFI) values from the received plurality of current and voltage values generated from photovoltaic reference cell sensors 350);
defining a first zone and a second zone within the solar array based on the plurality of diffuse fraction irradiance (DFI) values, the DFI values in the first zone being generally different from the DFI values in the second zone (see line 24-46, column 6 teaching during conditions of cloudy or overcast when the DHI exceeds the DNI, some trackers are set to a horizontal position to collect DHI and teaching the amount of DNI and a tracker controller can calculate the angle which provides the most irradiance possible by using sensors 350 which can be associated with individual trackers; the trackers which have a DHI value exceeding the DNI value during conditions of cloudy or overcast, sensed by sensors 350 and calculated by controller 345, are cited to read on the claimed first zone and the trackers which have a DNI value exceeding the DHI value, sensed by sensors 350 and calculated by controller 345, are cited to read on the claimed second zone);
determining a zone-specific solar tracker angle for the first zone and determining a zone-specific solar tracker angle for the second zone based on the plurality of DFI values, the zone-specific solar tracker angle for the first zone being different from the zone-specific solar tracker angle for the second zone (recall line 24-46, column 6 cited above and see line 47-62 teaching determining a zone-specific solar tracker angle for the cited first zone, such as zero degrees horizontal, and determining a zone-specific solar tracker angle for the cited second zone based on the plurality of DFI values, such as the angle 340 having the most irradiance at the normal position tracking the sun); and
positioning the solar trackers within the first zone to the zone-specific solar tracker angle determined for the first zone, and positioning the solar trackers within the second zone to the zone-specific solar tracker angle determined for the second zone (see line 33-60, column 4 teaching positioning the solar trackers such that they are oriented at the solar tacker angle which would correspond to each of the cited zone-specific solar tracker angles for each first and second zone).
Morse et al. teaches independent control designs for orienting solar modules in different zones independently to account for diffused irradiance from clouds or overcast (see line 24-62, column 6) but does not teach the control designs include mapping and generating a digital image to represent the diffused fraction irradiance.
However, Hoff discloses a control design for orienting solar modules to account for diffused irradiance from clouds or overcast comprising:
receiving current and voltage values generated from a plurality of solar modules of the solar array (see [0069] teaching receiving “power statistics, including a time series of the power statistics for the photovoltaic plant… The photovoltaic plant configuration specification includes power generation and location information, including direct current (“DC”) plant and photovoltaic panel ratings…voltage at point delivery”);
calculating a diffuse fraction irradiance (DFI) for the plurality of solar modules (see [0209-0210] and [0240] teaching calculating a diffuse fraction irradiance);
mapping the diffuse fraction irradiance for the plurality of solar modules (see [0069-0073] and [0287-0288] teaching mapping from calculated irradiance statistics combined with the photovoltaic fleet configuration to generate the high-speed time series photovoltaic production data and simulation with different geographical tiles);
generating a digital image of light conditions in the solar array based on the mapped diffuse fraction irradiance (see [0069-0073] and [0079] teaching “power output data 19 for a photovoltaic plant is generated using observed field conditions relating to overhead sky clearness. Solar irradiance 23 relative to prevailing based weather stations 24. Solar irradiance measurements can also be derived or inferred by the actual power output of existing photovoltaic systems 25. Additionally, satellite observations 26 can be obtained for the geographical region” and “satellite imagery data is pixel-based, the data for the geographical region is provided as a set of pixels, which span across the region and encompassing the photovoltaic fleet”);
determining a solar tracker angle based on mapped diffuse fraction irradiance (see [0069-0073], [0203-0204], and [0221-0222] teaching “tracking mode”, “shading and physical obstructions can be evaluated by specifying obstructions as part of a system’s configuration specification”, “Perform this analysis for all angles to tune for the effects of obstructions within the sun’s path”);
transmitting the solar tracker angle to a computing device associated with each solar tracker in the solar array (see [0069-0073] “computer system 21 executes the methodology described infra which can be stored or provided 27 to planners and other interested parties” and “data feeds 29a-c from the various sources of solar irradiance data”); and
driving the solar trackers such that the solar trackers are oriented to the same angle (see [0203-0204], [0221-0222], and [0226-0227] teaching “a two-step approach can be used to quantify the effect of obstructions on diffuse and direct irradiance. Combining the effect of obstructions by performing the two steps, as discussed in detail infra, results in an equivalent shading and physical obstruction profile that can be used with the system's configuration specification when forecasting photovoltaic production”, “This process will result in a profile that simultaneously modifies the obstruction angles that affect direct irradiance and adjust the angles to retain the correct overall diffuse obstructions.”, and “to improve performance through changes to the plant's operational features, such as revising tracking mode (fixed, single-axis tracking, dual-axis tracking), azimuth, tilt, row-to-row spacing, tracking rotation limit, and shading configurations. Moreover, the accuracy or degree to which a system configuration is “optimal” can be improved further by increasing the degree by which each of the configuration parameters is varied. For instance, tilt angle can be permuted in one degree increments, rather than five degrees at a time. Still other ways of structuring or permuting the configuration parameters, as well as other uses of the hypothetical photovoltaic system configurations, are possible.”).
Thus, at the time of the invention, it would have been obvious to a person to having ordinary skill in the art to have substituted the control designs for each first and second zone of Morse et al. for the control design of Hoff because the simple substitution of a known element known in the art to perform the same function, in the instant case a control design to orient solar modules taking account for diffused light, supports a prima facie obviousness determination (see MPEP 2143 B).
Hoff teaches adjusting the received voltage and current data of the solar modules supported by the solar trackers (see [0069-0073], [0128], and [0226-0232]) but does not disclose accounting for a decrease in output that is expected to occur as a function of time for any of the plurality of solar modules.
However, Jungerman et al. teaches a method of controlling a solar array (see Abstract) and discloses accounting for a decrease in output that is expected to occur as a function of time for the solar modules (see [0002-0006] and [0038] teaching “it is desirable to monitor the performance of the solar panels to detect degradation due to aging, faults, or environmental conditions, because even minor degradation in performance of one or more solar panels can deprive the PV system of significant energy production over the long operating life of the solar panels” which is cited to provide for the claimed accounting “for a decrease in output that is expected to occur as a function of time” because Jungerman et al. teaches an expected decrease in output/energy production due to degradation as a function over time/aging and monitors the solar panels to detect and account for the degradation).
Thus, at the time of the invention, it would have been obvious to a person having ordinary skill in the art to have modified the adjusting received voltage and current data in the method of Morse et al., as modified by Hoff above, to include accounting for a decrease in output that is expected to occur as a function of time, as suggested by Jungerman et al., because it would have led to identifying a cause of significant energy production loss over the operating life of the modules.
Morse et al., as modified above, teaches the claimed calculating a plurality of DFI values using the adjusted received plurality of current and voltage values “to improve accuracy of the calculating of the plurality of DFI values” because Morse et al., as modified above, teaches adjusting the received current and voltage values to account for degradation due to aging which would improve the accuracy of the calculating of the plurality of DFI values as it accounts for degradation.
With regard to claim 17, independent claim 16 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Morse et al. discloses wherein
defining the first zone and the second zone within the solar array provides for granularity in controlling the solar array to improve overall output of the solar array (the cited defining the first zone and the second zone within the solar array is cited to provide for the claimed “provides for granularity in controlling the solar array to improve overall output of the solar array” because it provides individual control of tracker angles within the first zone and second zone when the DHI value exceeds the DNI value and when the DNI values exceeds the DHI value which improves overall output of the solar array by utilizing maximum irradiance in each individual zone).
With regard to claim 21, independent claim 16 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above. Morse et al. discloses further comprising
repeating the steps of the method at intervals of time such that a solar tracker defined to be within the first zone during a first interval of time is defined to be within the second zone during a second interval of time (see line 34-62, column 10 teaching interval sampling until trackers in the cited first zone when the DHI exceeds the DNI have conditions changed to clearer skies and the DNI exceeds the DHI which is the cited second zone).
With regard to claims 19 and 20, independent claim 16 is obvious over Morse et al. in view of Hoff and Jungerman et al. under 35 U.S.C. 103 as discussed above.
Morse et al., as modified by Hoff above, teaches receiving a plurality of current and voltage values but does not disclose adjusting the current and voltage values to account for degradation of any of the plurality of solar modules.
However, Jungerman et al. teaches a method of controlling a solar array (see Abstract) and discloses accounting for degradation of the solar modules (see [0002-0006] and [0038] teaching “it is desirable to monitor the performance of the solar panels to detect degradation due to aging, faults, or environmental conditions, because even minor degradation in performance of one or more solar panels can deprive the PV system of significant energy production over the long operating life of the solar panels” wherein the detected degradation due to aging is based on an expected decrease in output over time due to the “aging” over time).
Thus, at the time of the invention, it would have been obvious to a person having ordinary skill in the art to have adjusted the received voltage and current data in the method of Morse et al., as modified by Hoff above, to include accounting for degradation, as suggested by Jungerman et al., because it would have led to identifying a cause of significant energy production loss over the operating life of the modules.
Response to Arguments
Applicant's arguments filed November 26, 2025 have been fully considered but they are not persuasive.
Applicant notes the newly added claimed limitations are not found within the previously cited prior art references. However, this argument is addressed in the rejections of the claims above.
Conclusion
THIS ACTION IS MADE FINAL. Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
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/DUSTIN Q DAM/Primary Examiner, Art Unit 1721 February 23, 2026