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Minimum C h a r g e Theminimum monthly bill will be the demand charge for 5 kilowatt plus actual energy charges., Maximum Charge Themaximum monthly charge shall be the higher of (1) the minimum charge or (2) the combined average cost of $0.25 per kilowatt hour for demand and energy charges., Energy C h arge Perkilowatt hour for the first 100 hours of the maximum demand (never less than 100 kilowatts) . . . . . . . . . . . . . . . . $ 0 . 0 6 2 7 9 Perkilowatt hour for the next 300 hours of the maximum demand (never less than 100 kilowatts) . . . . . . . . . . . . . . . . $ 0 . 0 3 0 0 1 Perkilowatt hour for the next 100 hours of the maximum demand (never less than 100 kilowatts) . . . . . . . . . . . . . . . . $ 0 . 0 2 0 3 8 Perkilowatt hour for all use in excess of 500 hoursuseof the maximum demand (never less than 1 0 0 k i l o w a t ts) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0 . 0 1 0 7 5 Minimum C h a r g e Theminimum monthly bill will be the demand charge plus the energy charge of 100 hours use thereof., The rate for this service will be $3.24 per Kw of demand., The monthly standby demand charge will be based on the trailing 12 month peak demand at the time of execution of the contract.

In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h).

Forecasted energy demand in California is set to increase over the next 10 – 20 years., The two main driving forces of demand growth are climate change and the adoption of EVs., Climate change will be responsible for an increased energy demand in the summer months., This will likely increase peak demand, as well as the total amount of energy consumed., EV adoption will increase demand in the off-peak times as EV owners charge cars overnight.

CUSTOMER LOAD GROWTH AND DEMAND-SIDE MANAGEMENT _____ a., DEMAND-SIDE MANAGEMENT 43 7., As natural gas demand continues to grow, additional supply and transmission infrastructure will need to be developed to address future increases in demand., NorthWestern’s Energy Supply function is then charged with ensuring it has enough natural gas supply lined up to meet Design Day needs., Storage is filled in the summer during months of low demand.

 NorthWestern Energy Schedule O‐8 Electric Utility ‐ State of South Dakota Page 1 of 2 Pro Forma Year Ending December 31, 2022 Derivation of Increased Rates and Proof of Revenue Billing Billing Line Description Units Rate Revenue Units Rate Revenue $ % 1 Commercial & Industrial Service Rate 33 2 Summer Rate 3 Demand Charge 237,921 $11.05 $2,629,024 237,921 $14.13 $3,361,819 $732,796 27.87% 4 Power Factor Charge 294,039 $14.13 375,997 81,958 27.87% 5 First 100 kWh per kW 21,584,573 $0.06659 1,437,317 21,584,573 $0.07887 1,702,375 265,059 18.44% 6 Next 300 kWh per kW 33,383,062 $0.04580 1,528,944 33,383,062 $0.05424 1,810,697 281,753 18.43% 7 Next 100 kWh per kW 1,862,545 $0.02706 50,400 1,862,545 $0.03204 59,676 9,275 18.40% 8 Over 500 kWh per kW 642,889 $0.01455 9,354 642,889 $0.01723 11,077 1,723 18.42% 9 Primary Discount 10 MAX33 Revenue ‐343,438 ‐406,686 ‐63,248 18.42% 11 Sub‐total Summer Rate 57,473,069 $5,605,640 57,473,069 $6,914,956 $1,309,316 23.36% 12 Booked, to Billed Revenue Ratio 100.041% 100.00% 13 Booked Base Rate Revenue $5,607,952 $6,914,956 $1,307,004 23.31% 14 Off‐Peak Rate 15 Demand Charge 440,506 $11.05 $4,867,594 440,506 $14.13 $6,224,354 $1,356,759 27.87% 16 Power Factor Charge 429,319 548,984 119,665 27.87% 17 First 100 kWh per kW 39,856,971 $0.06659 2,654,076 39,856,971 $0.07887 3,143,519 489,444 18.44% 18 Next 300 kWh per kW 59,102,384 $0.04580 2,706,889 59,102,384 $0.05424 3,205,713 498,824 18.43% 19 Next 100 kWh per kW 3,073,121 $0.02706 83,159 3,073,121 $0.03204 98,463 15,304 18.40% 20 Over 500 kWh per kW 1,276,166 $0.01455 18,568 1,276,166 $0.01723 21,988 3,420 18.42% 21 Primary Discount 22 MAX33 Revenue ‐661,833 ‐783,716 ‐121,883 18.42% 23 Sub‐total Off‐Peak Rate 103,308,642 $10,097,772 103,308,642 $12,459,306 $2,361,534 23.39% 24 Booked to Billed Revenue Ratio 99.894% 100.00% 25 Booked Base Rate Revenue $10,087,099 $12,459,306 $2,372,207 23.52% 26 27 Annual Subtotal Rate 33 160,781,711 $15,703,412 160,781,711, $19,374,262 3,670,850 23.38% 28 Booked to Billed Revenue Ratio 99.947% 100.000% 29 Total Adjusted Annual Commercial Rate 33 Revenue 160,781,711 $15,695,051 160,781,711 $19,374,262 3,679,211 23.44% ‐‐‐‐‐‐‐‐‐‐ Present Rates ‐‐‐‐‐‐‐‐‐‐‐ ‐‐‐‐‐‐‐‐‐‐ Proposed Rates ‐‐‐‐‐‐‐‐‐‐ Revenue Change NorthWestern Energy Schedule O‐8 Electric Utility ‐ State of South Dakota Page 2 of 2 Pro Forma Year Ending December 31, 2022 Derivation of Increased Rates and Proof of Revenue Billing Billing Line Description Units Rate Revenue Units Rate Revenue $ % 1 Commercial & Industrial Service Rate 33YS 2 Summer Rate 3 Demand Charge 1,006 $11.05 $11,122 1,006 $14.13 $14,222 $3,100 27.87% 4 Power Factor Charge 0 0 0 0.00% 5 First 100 kWh per kW 100,518 $0.06659 6,693 100,518 $0.07887 7,928 1,234 18.44% 6 Next 300 kWh per kW 153,844 $0.04580 7,046 153,844 $0.05424 8,344 1,298 18.43% 7 Next 100 kWh per kW 0 $0.02706 0 0 $0.03204 0 0 #DIV/0!, 8 Over 500 kWh per kW 0 $0.01455 0 0 $0.01723 0 0 0.00% 9 MAX33 Revenue 0 0 0 $0.00000 0 0 0.00% 10 YS Discount 4,252 0 $0.00000 4,252 0 0.00% 11 Sub‐total Summer Rate Before YS Discount 254,362 $24,861 254,362 $30,494 5,633 22.66% 12 Booked to Billed Revenue Ratio 100.167% 100.00% 13 Booked Base Rate Revenue $24,903 $30,494 5,591 22.45% 14 Off‐Peak Rate 15 Demand Charge 1,432.75 $11.05 $15,832 1,433 $14.13 $20,245 $4,413 27.87% 16 Power Factor Charge 187 239 52 27.87% 17 First 100 kWh per kW 143,317 $0.06659 9,543 143,317 $0.07887 11,303 1,760 18.44% 18 Next 300 kWh per kW 239,507 $0.04580 10,969 239,507 $0.05424 12,991 2,021 18.43% 19 Next 100 kWh per kW 0 $0.02706 0 0 $0.03204 0 0 0.00% 20 Over 500 kWh per kW 0 $0.01455 0 0 $0.01723 0 0 0.00% 21 MAX33 Revenue 0 0 $0.00000 0 0 0.00% 22 YS Discount 6,400 0 $0.00000 6,400 0 0.00% 23 Sub‐total Off‐Peak Rate Before YS Discount 382,824 $36,532 382,824 $44,778 $8,246 22.57% 24 Booked to Billed Revenue Ratio 99.538% 100.00%

RATE Customer charge per month – negotiated rate not to exceed* $330.00 Demand Charge – Extended Service: (Firm Supply Only) Pertherm daily contract demand 1 s t 5 0 0 t h e r m s / d a y (never less than 50 therms) $0.24590 O v e r 5 0 0 t h e rms/day $ 0 .00000 Non-Gas Transportation Rate (Rate 94)* Negotiated R a t e P e r T h e rm Not to Exceed ......... $0.05911 CityApproved Economic Development Surcharge $ 0 .00254 (Includes Kearney, North Platte and Grand Island., Minimum Charge Customer Charge + Demand Charge(if applicable) *In no event shall the demand charge (if applicable), plus the total of the customer charge and the revenue from the transportation rate, be less than the incremental cost of serving each customer in this class., T h e c u s t o m e r s h a l l b e r e s p o n s i b l e f o r any imbalance or other charges or penalties in the event such charges are levied against the Company by pipeline transporters in connection with loads transported pursuant to this tariff schedule. 4., I f t h e c u s t omer takes unauthorized gas during the periods of curtailment, a penalty rate which is the greater of $3.00 per therm or the maximum penalty charges permitted to be made by the Company’s upstream service providers for takes of natural gas in addition to the regular Commodity Charge for such gas.

 NorthWestern Energy Schedule O‐9 Electric Utility ‐ State of South Dakota Page 1 of 5 Pro Forma Year Ending December 31, 2022 Derivation of Increased Rates and Proof of Revenue Billing Billing Line Description Units Rate Revenue Units Rate Revenue $ % 1 Large Commercial and Industrial Rate 34 2 Summer Rate 3 Demand Charge ‐ First 100 kW 203,100 $11.05 $2,244,259 203,100 $14.13 $2,869,808 $625,549 27.87% 4 Demand Charge ‐ Next 400 kW 198,557 $9.79 1,943,877 198,557 $12.52 2,485,938 542,062 27.89% 5 Demand Charge ‐ Next 500 kW 186,424 $8.53 1,590,199 186,424 $10.91 2,033,888 443,690 27.90% 6 Total Demand Charge 588,082 $5,778,334 588,082 $7,389,634 $1,611,300 27.89% 7 Power Factor Charge Revenue 168,515 215,486 46,971 27.87% 8 MIN34 Revenue 42,971 54,940 11,969 27.85% 9 Energy Charge ‐ First 100 X Demand 58,097,495 $0.04911 2,853,168 58,097,495 $0.06279 3,647,942 794,774 27.86% 10 Energy Charge ‐ Next 300 X Demand 141,880,980 $0.02348 3,331,365 141,880,980 $0.03001 4,257,848, 55,572 12,107 27.86% 10 Energy Charge ‐ Next 300 X Demand 2,653,500 $0.02348 62,304 2,653,500 $0.03001 79,632 17,327 27.81% 11 Energy Charge ‐ Next 100 X Demand 686,700 $0.01595 10,953 686,700 $0.02038 13,995 3,042 27.77% 12 Energy Charge ‐ Remaining kWh 72,500 $0.00841 610 72,500 $0.01075 779 170 27.82% 13 Total Energy Charge 4,297,750 $117,332 4,297,750 $149,978 $32,647 27.82% 14 Sub‐total Summer Rate $201,920 $258,157 $56,237 27.85% 15 Booked to Billed Revenue Ratio 100.181% 100.00% 16 Booked Base Rate Revenue $202,285 $258,157 $55,872 27.62% 17 Off‐Peak Rate 18 Demand Charge ‐ First 100 kW 1,600 $11.05 $17,680 1,600 $14.13 $22,608 $4,928 27.87% 19 Demand Charge ‐ Next 400 kW 5,790 $9.79 56,687 5,790 $12.52 72,494 15,807 27.89% 20 Demand Charge ‐ Next 500 kW 3,526 $8.53 30,076 3,526 $10.91 38,468 8,392 27.90% 21 Total Demand Charge 10,916 $104,443 10,916 $133,570 $29,127 27.89% 22 Power Factor Charge Revenue 223 285 62 28.07% 23 Option L Discount ‐2,780 ‐3,554 ‐774 27.84%, 10 Energy Charge ‐ Next 300 X Demand 8,284,458 $0.02348 194,519 8,284,458 $0.03001 248,617 54,098 27.81% 11 Energy Charge ‐ Next 100 X Demand 1,335,191 $0.01595 21,296 1,335,191 $0.02038 27,211 5,915 27.77% 12 Energy Charge ‐ Remaining kWh 1,026,144 $0.00841 8,630 1,026,144 $0.01075 11,031 2,401 27.82% 13 Total Energy Charge 13,527,522 $365,967 13,527,522 $467,803 $101,836 27.83% 14 Sub‐total Summer Rate $621,770 794,973 173,203 27.86% 15 Booked to Billed Revenue Ratio 100.191% 100.00% 16 Booked Base Rate Revenue $622,957 $794,973 $172,015 27.61% 17 Off‐Peak Rate 18 Demand Charge ‐ First 100 kW 1,900 $11.05 $20,995 1,900 $14.13 $26,847 $5,852 27.87% 19 Demand Charge ‐ Next 400 kW 7,144 $9.79 69,940 7,144 $12.52 89,443 19,503 27.89% 20 Demand Charge ‐ Next 500 kW 51,120 $8.53 436,055 51,120 $10.91 557,721 121,666 27.90% 21 Total Demand Charge 60,164 $526,990 60,164 $674,011 $147,021 27.90% 22 Power Factor Charge Revenue 45,842 58,620 12,778 27.87% 23 Option L Discount $0.00000, 27.86% 10 Energy Charge ‐ Next 300 X Demand 10,656,818 $0.02348 250,222 10,656,818 $0.03001 319,811 69,589 27.81% 11 Energy Charge ‐ Next 100 X Demand 3,262,531 $0.01595 52,037 3,262,531 $0.02038 66,490 14,453 27.77% 12 Energy Charge ‐ Remaining kWh 2,342,660 $0.00841 19,702 2,342,660 $0.01075 25,184 5,482 27.82% 13 Total Energy Charge 19,894,065 $500,331 19,894,065 $639,542 $139,210 27.82% 14 Sub‐total Summer Rate $838,795 1,072,431 233,636 27.85% 15 Booked to Billed Revenue Ratio 100.178% 100.00% 16 Booked Base Rate Revenue $840,292 $1,072,431 $232,139 27.63% 17 Off‐Peak Rate 18 Demand Charge ‐ First 100 kW 2,000 $11.05 $22,100 2,000 $14.13 $28,260 $6,160 27.87% 19 Demand Charge ‐ Next 400 kW 7,191 $9.79 70,402 7,191 $12.52 90,034 19,632 27.89% 20 Demand Charge ‐ Next 500 kW 43,206 $8.53 368,550 43,206 $10.91 471,381 102,831 27.90% 21 Total Demand Charge 52,398 $461,052 52,398 $589,675 $128,623 27.90% 22 Power Factor Charge Revenue 56,262 71,944 15,682 27.87% 23 Option, 8,237 1,792 27.81% 11 Energy Charge ‐ Next 100 X Demand 7,157 $0.01595 114 7,157 $0.02038 146 32 27.77% 12 Energy Charge ‐ Remaining kWh 0 $0.00841 0 0 $0.01075 0 0 0.00% 13 Total Energy Charge 381,755 $11,476 381,755 $14,669 $3,194 27.83% 14 Sub‐total Summer Revenue Before YS Discount 22,286 28,493 6,207 27.85% 15 Booked to Billed Revenue Ratio 100.174% 100.00% 16 Booked Base Rate Revenue $22,324 $28,493 $6,168 27.63% 17 Off‐Peak Rate 18 Demand Charge ‐ First 100 kW 1,600 $11.05 $17,680 1,600 $14.13 $22,608 $4,928 27.87% 19 Demand Charge ‐ Next 400 kW 263 $9.79 2,579 263 $12.52 3,299 719 27.89% 20 Demand Charge ‐ Next 500 kW 0 $8.53 0 0 $10.91 0 0 0.00% 21 Total Demand Charge 1,863 $20,259 1,863 $25,907 $5,647 27.87% 22 Power Factor Charge Revenue 1 1 $0 81.82% 23 YS Discount $0.00000 ‐11,389 0 $0.00000 ‐11,389 24 Energy Charge ‐ First 100 X Demand 186,348 $0.04911 $9,152 186,348 $0.06279 11,701 $2,549 27.86% 25 Energy Charge ‐ Next 300 X Demand 473,474 $0.02348 11,117

The base revenue 13 CSF-8 requirements addressed in this filing reflect the fixed costs of 1 providing utility services to our customers and therefore are not 2 dependent upon a customer’s kWh usage. 3 4  Demand Charges ($/kW): A demand charge is for costs of the 5 energy infrastructure used – distribution, transmission, and 6 capacity-related power generation – to deliver energy service and 7 to meet a customer’s peak energy demand., A cost-based rate design would 17 include the charges described above – energy/volumetric rates, demand 18 charges, and monthly service/customer charges., Any increase to monthly service charges would 1 result in a compensating decrease to energy and demand charges to 2 ensure the rate design remains revenue neutral, that is, the rates 3 developed will continue to recover the same allocated costs of service for 4 the customer class., A rate structure that has a higher monthly service, or 5 fixed, charge can reduce month-to-month bill volatility that may result from 6 changes in usage and/or demand from month to month. 7 Table 5: Current and Cost-Based Monthly Service Charges – Electric Current Cost- Based Change ($) Change (%) RESIDENTIAL $4.20 $9.94 $5.74 136.7% GS‐1: SECONDARY Non‐Demand $6.00 $10.43‐10.51 5 $4.43‐4.51 73.8‐75.1% Demand $8.70 $49.28‐$57.18 6 $40.58‐48.48 466.4‐557.2% GS‐1: PRIMARY Non‐Demand $8.80 $14.57 $5.77 65.6% Demand $27.70 $269.85‐ $508.76 7 $242.15‐ 481.06 874.2‐ 1,736.7% GS‐2 SUBSTATION $225.00 $1,613.74 $1,388.74 617.2% GS‐2 TRANSMISSION $1,380.00 $2,083.87 $703.87 51.0% IRRIGATION Non‐Demand $45.20 $58.72 $13.52 29.9% Demand $106.50 $228.35 $121.85 114.4% 5 This reflects the difference between choice and non-choice customers with $10.43 for GS1 Sec Non Dmd Choice and $10.51 for GS1 Sec Non Dmd Non Choice. 6 This reflects the difference between, It can impact the bills customers will pay 8 due to changes in the manner (i.e., energy charge, demand 9 charge, and/or monthly service fee) by which NorthWestern seeks 10 to recover cost of service from customers. 11 Further details regarding customer bill impacts are discussed by Mr. 12 Durkin. 13 14 Q.

In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h).

. . . . . . . . . . $ 0 . 0 1 4 5 5 0 .01723 Minimum C h a r g e Theminimum monthly bill will be the demand charge for 5 kilowatt plus actual energy charges., Maximum Charge Themaximum monthly charge shall be the higher of (1) the minimum charge or (2) the combined average cost of $0.20 0.25 per kilowatt hour for demand and energy charges., Energy C h arge Perkilowatt hour for the first 100 hours of the maximum demand (never less than 100 kilowatts) . . . . . . . . . . . . . . . . $ 0 . 0 4 9 1 1 0 .06279 Perkilowatt hour for the next 300 hours of the maximum demand (never less than 100 kilowatts) . . . . . . . . . . . . . . . . $ 0 . 0 2 3 4 8 0 .03001 Perkilowatt hour for the next 100 hours of the maximum demand (never less than 100 kilowatts) . . . . . . . . . . . . . . . . $ 0 . 0 1 5 9 5 0 .02038 Perkilowatt hour for all use in excess of 500 hoursuseof the maximum demand (never less than 1 0 0 k i l o w a t ts) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0 . 0 0 8 4 1 0 .01075 Minimum C h a r g e Theminimum monthly bill will be the demand charge plus the energy charge of 100 hours use thereof., The rate for this service will be $3.24 per Kw of demand., The monthly standby demand charge will be based on the trailing 12 month peak demand at the time of execution of the contract.

In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h).

In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h).

Dispatchability The a b i l i t y o f a g e n e r a t i n g r e source to deliver its output on demand., Grid.Balancer Energystoragesystemfrom Demand Energy used with Joule.System., Load S h i f t i n g Movingthetimeperiodofaportionofelectricity demand from higher demand hours to lower demand hours., Solar P V (seePhotovoltaic)Anelectricitygenerating resource that uses sunlight as fuel to create an electric charge in semiconductor panels., Time of Use A variable rate structure that charges customers a rate dependent on the time of day and season the energy is used.

Electrons flow in the reverse directio n during a charge cycle when energy is drawn from the grid., The liquid electrolyte used for charge -discharge reactions is stored externally and pumped through the cell., The variable costs to charge the PHES system have not been inc luded in the technology summary tables herein., More currently, the trend in rate design is to adopt demand charges and/or time -of-day rates to reflect time-of-day energy costs in time-of-use rates., Load Shifting Moving the time period of a portion of electricity demand from higher demand hours to lower demand hours.

“Exploring a Resource A d e q u a c y Program for the Pacific Northwest” • Resource A d equacy (RA) is the ability to serve load across a broad range of conditions, subject to a long-run reliability standard • An RA p r ogram is a regulatory planning framework that aims to ensure there are enough resources available to serve peak electric demand under most conditions, e.g. 1-day-in-10 years, and that those resources can deliver energy where it is needed • A k e y requirement of an RA program is a Planning Reserve Margin (“PRM”) expressed as a percentage above peak load that is required to be held on a forward-looking basis • A P R M is an output determined by the adequacy standard • An RA p r ogram also defines a set of rules that apply to the entities that are covered by the program • For example, peak load forecasting methodology, how to count contribution of VERs, penalties for non-compliance, etc., In the day-ahead and operating day time frames, each entity commits to make excess capacity available to other participants who are experiencing high loads, low VER generation, and/or excess generation outages Northwest Power Pool Program Elements 10 • Thermal Resources • Unforced Capacity (UCAP) methodology (reflects resource-specific outage history) during capacity critical hours • Storage Hydro • Methodology unique to NWPP program • Reflects operational restrictions during historical capacity critical hours • Likely will apply to a portion of NorthWestern’s fleet • Run-of-river Hydro • Effective Load Carrying Capability (ELCC) analysis • Will apply to a portion of NorthWestern’s fleet Qualified Capacity Contribution (QCC) 11 • Va riable Energy Resources • ELCC analysis • Energy Storage (battery and pumped hydro) • QCC based on 5-hour duration requirement • Hybrid Facilities • Sum of the Parts methodology • PO may adjust QCC for facilities that cannot be grid-charged, • Customer Resources • Demand response, behind-the-meter generation • Must be controllable and dispatchable • Potentially could be registered as a load modifier or as a capacity resource Qualified Capacity Contribution (QCC) 12 • Tr ansmission Objectives • Encourage procurement of firm transmission service sufficient to demonstrate deliverability of resources to load, while recognizing the need for flexibility where necessary or appropriate, • As a Balancing A uthority, we have an obligation to maintain service on our system • If a choice customer is short in a given hour, we have the ability to charge that customer for the energy shortage, but there is no mechanism in the OAT T to charge for the capacity needed to provide that energy • Similarly, we have no authority under the OAT T to curtail a specific customer in the event of a shortage Third Party Loads 19

The Project generally concentrated on the various aspects of advanced volt/VAR control, distribution automation, automated outage restoration, substation capacity, advanced metering infrastructure, and customer demand response, control and energy management., o Ensuring that no “debit” was be charged to customer if usage increased., Software checkout of the Lockheed Martin (“LM”) SeeLoad/SeeGrid demand response application failed due to interface revision errors., Additional steps planned for completion but not achieved included:  Integration of LM SeeLoad/SeeGrid demand response application to Metcalf head end building automation control system, The successful demand response events closely matched initial predictions of power reduction on the order of 1,500 – 3,000 megawatt hours per year for HVAC and deferred a little more than one- third of a megawatt of load for an hour at a time for chiller loads.

Benton PUD sought to demonstrate that these units could charge when a local wind farm produced energy, and then discharge this power during the PUD’s peak demand periods, making better use of the wind energy and helping to fatten the utility’s demand curve., As for BPA d e m a n d charges (a fee that helps BPA e n s u re that power is available to utilities during high electricity demand periods), if voltage management was exercised all year, the utility might have reduced its demand charges by at least $6,000 annually., The objective of the DRUs test was reduction of monthly system peak and corresponding demand charges (a fee that helps BPA e n s u re that power is available to utilities during high electricity demand periods)., Regarding BPA d e m a n d charges, and presuming the costs from the four months with data are similar to those of the remaining eight, the demonstration project estimates the yearly impact of battery operations on demand charge reductions to be from $80-160 per year., Per demand charges, actual curtailment events and advised transactive events largely failed to identify the monthly hours on which demand charges were, in fact, incurred.

Larger users with loads greater than 15 kilowatts (kW) require a demand meter and incur an additional demand charge., The demand charge is measured through a demand meter which registers the highest rate of electrical fow (current) for specifed time periods, usually 15 or 30 minute intervalsduring each billing period, independent of the kWh energy usage., Making decisions to use your pump based on the meter-reading schedule provided can help you better control your demand charges., Demand charges may be prorated, if used less than 25 days, on the frst and last billing periods., Prorating allows you to pay a partial demand charge that better matches the time of energy use.

In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h).

In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h).