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2020 Fourth Quarter FERC Form 1

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).
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Navigant NEM Cost Benefit Analysis Report 5-3-2019

Navigant estimated the amount of NEM solar that will be installed at NorthWestern distribution feeders based on (1) the number of customers receiving service under NorthWestern’s residential and general service rate classes (i.e., primary demand, primary non-demand, secondary demand, and secondary non- demand) at each substation, (2) an analysis of solar production’s coincidence with substation-level peak, and (3) seasonality., Navigant obtained substation capacity ratings and compared these ratings to seasonal peak demands projected at each substation; NorthWestern provided demand forecast projections for each substation., The team applied current rates for each of NorthWestern’s bill categories (i.e., supply energy, supply deferred costs, distribution energy, CTC-QF, USBC, transmission demand, and distribution demand) as applicable to customers with solar PV up to 50 kW, split by customer class (i.e., residential, general secondary demand, general secondary non-demand, general primary demand, and general primary non-demand)., This model incorporates the same generation base, demand forecasts, fuel prices, other operating costs, and plant parameters that are utilized throughout the market simulation modeling process., Navigant applies its own analysis to provide macroeconomic outlook and natural gas supply and demand data for the model, including infrastructure additions and configurations, and its own supply and demand elasticity assumptions.
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South Dakota-Nebraska At A Glance

The supply portion of the bill for natural gas is subject to twice yearly fuel cost adjustments and is shown separately from the delivery charge., ELECTRIC OPERATIONS - SOUTH DAKOTA Service Area Size 25 counties in eastern South Dakota Peak & Average Load Peak demand was approximately 344 MWs, the average daily load was approximately 200 MWs, and 1.68 million megawatt hours were supplied to customers during 2021., The chart to the right shows these various billing components for a NorthWestern Energy commercial customer with a monthly usage of 14,000 kWh and 40 kW demand., RAT E S 4 4 % C a r b o n - F r e e S O U T H D A K O TA 2 0 2 1 E L E C T R I C G E N E R AT I O N P O RTFOLIO BASED ON MWH OF OWNED AND LONG-TERM CONTRACTED RESOURCES Wind Owned 20.4% Wind Contracted 23.4% Coal Owned 52.2% Natural Gas/Other Owned 4.0% SOUTH DAKOTA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY ELECTRIC BILLING COMPONENTS JANUARY 1, 2022 USING 14,000 KWH & 40 KW DEMAND PER MONTH Demand 33% Energy Supply 43% Fuel and Purchased Power 20% Power Factor (85%) 4% RAT E S NORTHWESTERN ENERGY’S JANUARY 1, 2022 ELECTRIC COSTS BY SIZE & CUSTOMER TYPE1 Residential Commercial and Industrial Rate 21 Rate 33 Rate 34 Rate 34 Monthly kWh 750 1,500 14,000 180,000 650,000 Peak Monthly kW Demand N/A 0 40 500 1,000 ACTUAL MONTHLY E L E C T R I C B I L L J A N U A RY 1, 2022 Average Monthly Cost per kWh for Supply and Delivery $ 0.138 $ 0.146 $ 0.121 $ 0.095 $ 0.068 Average Monthly Cost $ 103.78 $ 219 $ 1,689 $ 17,181 $ 44,397 1 Rates effective January, SOUTH DAKOTA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY NATURAL GAS BILLING COMPONENTS JANUARY 1, 2022 USING 200 THERMS PER MONTH NEBRASKA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY NATURAL GAS BILLING COMPONENTS JANUARY 1, 2022 USING 200 THERMS PER MONTH Monthly Service Charge 5% Monthly Service Charge 4% Delivery Charge (with 2% MGP Refund Included) 15% Delivery Charge 12% Purchased Gas Commodity 80% Purchased Gas Commodity 84% NORTHWESTERN ENERGY’S JANUARY 1, 2022 ELECTRIC COSTS BY SIZE & CUSTOMER TYPE1 Residential Commercial and Industrial Rate 21 Rate 33 Rate 34 Rate 34 Monthly kWh 750 1,500 14,000 180,000 650,000 Peak Monthly kW Demand N/A 0 40 500 1,000 ACTUAL MONTHLY E L E C T R I C B I L L J A N U A RY 1, 2022 Average Monthly Cost per kWh for Supply and Delivery $ 0.138 $ 0.146 $ 0.121 $ 0.095 $ 0.068 Average Monthly Cost $ 103.78 $ 219 $ 1,689 $ 17,181 $ 44,397 1 Rates effective January 1, 2022; fuel and purchase power portion of
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NWPCC 2018-10 - Final Draft for PC - 7th Plan Mid-Term Assessment

The Northwest Public Power Association briefed NEEL on results of a survey that indicate large numbers of utilities are considering rate structure changes, including shifts to higher fixed charges., The difference between “load” and “demand” is transmission and distribution losses between point of generation and point of demand., The Regional Emerging Technology Advisory Committee is now charged with optimizing regional investment in emerging energy-efficient technologies., The Council formed a demand response advisory committee (DRAC) in August 2016 that has assisted the Council in several key areas; namely: defining demand response, providing data on planned and existing demand response programs, and highlighting key barriers to demand response implementation., KEY BARRIERS TO DEMAND RESPONSE IMPLEMENTATION The DRAC has spent significant time discussing the barriers to demand response.
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South Dakota-Nebraska At A Glance

The supply portion of the bill for natural gas is subject to twice yearly fuel cost adjustments and is shown separately from the delivery charge., ELECTRIC OPERATIONS - SOUTH DAKOTA Service Area Size 25 counties in eastern South Dakota Peak & Average Load Peak demand was approximately 333 MWs, the average daily load was approximately 200 MWs, and 1.72 million megawatt hours were supplied to customers during 2019., The chart to the right shows these various billing components for a NorthWestern Energy commercial customer with a monthly usage of 14,000 kWh and 40 kW demand., RAT E S 4 0 % C a r b o n - F r e e S O U T H D A K O TA 2 0 1 9 E L E C T R I C G E N E R AT I O N P O RTFOLIO BASED ON MWH OF OWNED AND LONG-TERM CONTRACTED RESOURCES Wind Owned 19% Wind Contracted 21% Coal Owned 57% Natural Gas/Other Owned 3% SOUTH DAKOTA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY ELECTRIC BILLING COMPONENTS JANUARY 1, 2020 USING 14,000 KWH & 40 KW DEMAND PER MONTH Demand 33% Energy Supply 44% Fuel and Purchased Power 19% Power Factor (85%) 4% RAT E S NORTHWESTERN ENERGY’S JANUARY 1, 2020 ELECTRIC COSTS BY SIZE & CUSTOMER TYPE1 Residential Commercial and Industrial Rate 21 Rate 33 Rate 34 Rate 34 Monthly kWh 750 1,500 14,000 180,000 650,000 Peak Monthly kW Demand N/A 0 40 500 1,000 ACTUAL MONTHLY E L E C T R I C B I L L J A N U A RY 1, 2020 Average Monthly Cost per kWh for Supply and Delivery $0.136 $0.144 $0.118 $0.093 $0.066 Average Monthly Cost $101.97 $216 $1,657 $16,766 $42,968 1 Rates effective JANUARY 1, 2020; fuel, SOUTH DAKOTA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY NATURAL GAS BILLING COMPONENTS JANUARY 1, 2020 USING 200 THERMS PER MONTH NEBRASKA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY NATURAL GAS BILLING COMPONENTS JANUARY 1, 2020 USING 200 THERMS PER MONTH Monthly Service Charge 9% Monthly Service Charge 8% Delivery Charge (with 2% MGP Refund Included) 28% Delivery Charge 24% Purchased Gas Commodity 63% Purchased Gas Commodity 68% JANUARY 2020 AVERAGE COST PER THERM NATURAL GAS SOLD TO RESIDENTIAL AND COMMERCIAL CUSTOMERS BY UTILITIES1 State Residential Commercial Colorado $0.59 $0.55 Illinois $0.64 $0.56 Iowa $0.62 $0.52 Kansas $0.72 $0.63 Michigan $0.73 $0.62 Minnesota NA NA Missouri $0.85 $0.68 Montana $0.65 $0.64 Nebraska $0.64 $0.54 NorthWestern Energy NE2 $0.59 $0.46 North Dakota $0.56 $0.53 South Dakota $0.60 $0.49 NorthWestern Energy SD2 $0.64 $0.44 Wisconsin $0.68 $0.58 Wyoming $0.70 $0.61 AVERAGE FOR REGION 3 $0.66 $0.58
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Montana At A Glance

Because Montana has deregulated natural gas and electric services, customer rates are “unbundled” and electric or natural gas supply is shown separately from delivery and transmission charges., Our control area average demand for 2019 was approximately 1,412 MWs per hour for the year on average, with total energy delivered of more than 12.3 million MWHs, for year ended December 31, 2019., Because Montana has deregulated natural gas and electric services, customer rates are “unbundled” and electric or natural gas supply components are separate from delivery charges., In 2007, Montana passed new laws curtailing the ability for consumers under 5 MW peak demand to purchase electricity from alternative suppliers., Montana customers fund energy effciency as a least-cost resource in supply rates and through the Universal System Benefts Charge (USBC).
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2019 Third Quarter FERC Form 3-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).
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2020 Irrigation Season Information

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.
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Complete Plan (PDF - 11 MB)

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.
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Application for Natural Gas Service

Yes No If Yes, address: City: Legal Description Township: Range: Section: ¼ Section: Subdivision: Block: Lot: Site Information Service Needed: Overhead Electric Underground Electric Gas City Limits Yes No Additional Options: Temporary Electric During Construction (Customer Charge) Load Information Electric: Phase: 1 Phase 3 Phase Panel Size: amps Demand: kW Panel Size: Amps Demand: kW Voltage: 120/240 120/208 277/480 Electrical Contractor Phone Wiring Permit Number Primary Electric Heat: 1 Meter 2 Meter Gas: Load Btu/hr (total input of all appliances) Heating/Plumbing Contractor Phone Delivery Pressure Required: 7”wc 14”wc 2psig 5psig Requested installation Date: (You must contact Nort hWestern Energy for actual installation date.)
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2019 First Quarter FERC Form 3-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).
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Appendix 2 Glossary

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.
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From 10-Q Third Quarter 2020

Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers., The change in gross margin for items impacting net income includes the following: • An increase in electric retail volumes and demand driven by warmer weather and customer growth, partly offset by lower industrial demand unrelated to the COVID-19 pandemic., Thus, the rates we are allowed to charge may or may not match our costs at any given time., Such technologies could also result in further declines in commodity prices or demand for delivered energy., Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives. 61 Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions.
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2020 Second Quarter FERC Form 3-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).
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Complete Plan

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.
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Purchased Gas Adjustment

 SOUTH DAKOTA GAS RATE SCHEDULE NORTHWESTERN CORPORATION d/b/a NORTHWESTERN ENERGY Section No. 3 SIOUX FALLS 424thRevised SheetNo.9a SOUTH DAKOTA Canceling 423rdRevised SheetNo.9a ADJUSTMENTCLAUSERATES PerTherm Delivered Cost of Energy Per Month Rate No. 81 - Residential Gas Service Gas Commodity Charge $0.91318 Rate No. 82 - General Gas Service Gas Commodity Charge $0.91318 Rate No. 84 - Commercial and Industrial-Firm GasDemand Charge, per therm of daily contract demand (never less than 50 therms) NNG Pipeline Capacity Costs N N G R a t e / T h e r m 30.48%ofTF12Base $0.9737 $0.27 31.83%ofTF12Variable $1.1684 0.40 37.69%ofTF5 $1.9471 0.31 GRI Fee $0.0000 0.00 SBA Surcharge $0.0000 0.00 GSR Surcharge $0.0000 0.00 Order528Surcharge $0.0000 0.00 Stranded 858 Surcharge $0.0000 0.00 Total Pipeline Capacity Costs $ 0.98 NNG R e fund - 0 . 0 9 S u p p ly Standby 0.07 B a lancing Services 0.09 Total D e mand Charge $ 1 . 0 5 Theabovepercentages are based on the Company, ’s contract demand profile with NNG ( 4 9 , 0 2 0 MMBtu.), Rate Schedule MMBtu Demand Percentage T F 1 2 Base 13,705 2 7 . 9 6 % T F 1 2 V a r iable 1 6 , 8 4 1 3 4 . 3 6 % T F 5 1 8 , 4 7 4 ( 1 ) 3 7 . 6 9 % T o tals 4 9 , 0 2 0 1 0 0 . 0 0 % (1)Service is contracted for 5 months (15.70% is 5/12ths of 37.69%) G a s C ommodity Charge G a s S u p p ly - AverageofNNGVentura,NBPLVenturaTransferPoint andNNGDemarcation first of month index gas p r ice $ 0 . 5 5 9 6 0 F u e l U s e – 0 . 7 3 % N N G a n d 1 . 5 5 % C o mpany L&U 0.01480 P ipeline Transportation Fee 0 . 0 0 3 7 6 S c h e d u ling Fee 0 . 0 0 1 4 1 FebruaryColdWeatherEvent12monthrecovery 0.32000 T o tal G a s Component Charge $ 0 . 8 9 9 5 7 D a t e F iled: October 4, 2021 Effective Date: October 2, 2021 Jeffrey D e c k e r IssuedBy:RegulatoryDepartment SOUTH DAKOTA GAS RATE SCHEDULE NORTHWESTERN CORPORATION d/b/a NORTHWESTERN ENERGY Section No. 3 SIOUX FALLS 323rdRevised SheetNo.9b SOUTHDAKOTA Canceling 322ndRevised SheetNo.9b ADJUSTMENT C L A U S E R A T E S ( C, o n t i n u e d ) P e r T h e r m Delivered Cost o f E n e r g y ( Continued): P e r Month Rate No. 85 - Commercial and Industrial-Interruptible Sales Service Gas Commodity Charge G a s S u p p ly - AverageofNNGVentura,NBPLVenturaTransferPoint andNNGDemarcation first of month index gas price 0.55960 F u e l U s e - 0 . 7 3 % N N G a n d 1 . 5 5 % C o mpany L&U 0.01480 P ipeline Transportation Fee 0 . 0 0 3 7 6 R e leased Capacity Surcharge 0 . 0 1 4 0 0 B a lancing Services 0 . 0 0 3 0 0 S c h e d u ling Fee 0 . 0 0 1 4 1 T o tal G a s Component Charge $ 0 . 5 9 6 5 7 Rate No. 86 – Gas Contract Sales Service Rate No. 86 Gas Commodity Charge – Group 1 $0.57587 Rate No. 86 Gas Commodity Charge – Group 2 $0.57587 Rate No. 86 Gas Commodity Charge – Group 3 $0.57587 Rate N o . 8 6 G a s I n d e x $ 0 . 8 9 5 8 7 Rate No. 87 - Gas Transportation Firm Supply Standby Service Gas Demand Charge, per therm of daily contract demand Rate No. 84 supply standby costs $0.07 RateNo, .84pipelinecapacitycosts 0.98 T o tal D e mand Charge $ 1 . 0 5 G a s C ommodity Charge Rate N o . 8 4 G a s Commodity Charge $ 0 . 5 7 9 5 7 Imbalance Cash-out Rate Index Points (Rate No. 84, 85, 86 and 87) Northern, Ventura 50%, Demarcation 50% Northern Border, Ventura\TP 100% less applicable fuel Ad Valorem Taxes Paid: Rate No. 81 - Residential Gas Service Commodity Charge $0.0053 Rate No. 82 - General Gas Service Commodity Charge $0.0034 Rate No. 84 – Comm. & Ind. – Firm Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 Rate No. 85 – Comm. & Ind. - Interrupt Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 Rate No. 86 – Contract Sales Service Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 Rate No. 87 – Gas Transportation Service Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 DateFiled: October 4, 2021 Effective Date: October2,2021 Jeffrey D e c k e r IssuedBy:RegulatoryDepartment
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Form 10-Q Second Quarter 2020

Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers., Thus, the rates we are allowed to charge may or may not match our costs at any given time., Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating., Such technologies could also result in further declines in commodity prices or demand for delivered energy., Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions.
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2021 First Quarter FERC Form 3-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).
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Form 10-Q Third Quarter 2021

As a result of the project discontinuance, we recorded a $1.2 million pre-tax charge in the three months ended September 30, 2021, for the write-off of preliminary construction costs., Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers., As a result of the project discontinuance, we recorded a $1.2 million pre-tax charge for the write-off of preliminary construction costs., Thus, the rates we are allowed to charge may or may not match our costs at any given time., Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions.