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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., A decrease in the region’s electric capacity may impair the reliability of the grid, particularly during peak demand periods., 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.

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).

Environmental Protection Agency (EPA) -AFederal agency charged with protecting the environment., The demand for natural gas largely depends upon weather conditions., 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., This charge is recorded within other income, net on the Consolidated Statements of Income.

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.

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).

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).

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

Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month., Footnote any demand not stated on a megawatt basis and explain. 7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j)., Do not report net exchange. 7.Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred.

This included large industrial customers, utilities in the region, developers, demand-side aggregators, and others., NorthWestern’s primary periods of peak demand occur in the winter months in addition to some summer months., The periods of peak demand are generally served by dispatchable generation resources., This could include electric generation, energy storage, and/or demand response (“DR”)/demand side management (“DSM”) programs as explained further in this document., Cycles Assumed per Day (Associated with Pricing) cycles Charge Rate kW/min Aggregate Demand Side Capacity Reduction / Capability MW Customer / Facility Characteristics (Expand, if Multiple) Facility Type type Capacity Reduction / Capability MW Time of Day / Seasonal hourly, monthly, etc.

NorthWestern Energy 2021 fourth quarter FERC form

Applicability Thisrateisavailableforfirm gas volumes, on a contract basis, to commercial and industrial customers who may also require volumes of interruptible gas in excess of firm demand volumes for which they have contracted. 2., Rates Monthly C h a r g e s : C u s t o m e r C h a r g e per Meter: $ 80.00 D e m a n d C h a r g e – S t a n d a r d S e r v i ce: Per therm daily contract demand (never less than 50 therms) $ 0.21910 DemandCharge–ExtendedService: Per therm daily contract demand 1 st 500 therms/day (never less than 50 therms) $ 0.24590 Over 5 0 0 t h e rms/day $ 0 .00000 Non-Gas Commodity Charge: All u s e , p e r t h e r m $ 0 .05911 City Approved Economic Development Surcharge $ 0 .00254 Minimum Monthly Bill -Amount for therms of demand billed and the customer charge Adjustment C l a u s e s : a ., In addition, the new daily use may then become the daily firm contract demand in place of the previous demand determined by the customer and cannot be reduced by the customer for a period of twelve months. 5.

Our electric supply from owned and long-term contracted resources is not adequate to meet our peak- demand needs., Because of this, the volatility of market prices for energy on peak-demand days, even if only for a few days in duration, exposes us to potentially significant market purchases that could negatively impact our results of operations and cash flows., Our owned and long-term contracted resources are inadequate to supply the necessary capacity we require to meet our peak-demand loads, which exposes us to large quantities of market purchases at typically high and volatile energy prices., We remain concerned regarding an overall lack of capacity in the West and our owned and long-term contracted capacity deficit to meet peak-demand loads., Income tax expense for the three months ended March 31, 2023 includes a one- time $3.2 million charge for the reduction of previously claimed alternative minimum tax credits.

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., We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing., 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.

$25.00 /door N/A $ HVAC Demand Control Ventilation Must have space cooling with VFD on supply and return/relief fans, $35.00 / HP supply fan $ Cooking Hood Demand Control System Automated fan speed control. $0.50 / CFM of make-up air $ Faucet Aerator - Kitchen Must have electric water heating and be ≤ 1.5 GPM aerator., This proof of purchase must show: (1) the date of purchase and itemized price paid, (2) the size, type, make, model or part number for the products, and (3) a description of any installation or other labor charges.

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).

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.)

They may claim there is a cost for this service and demand payment immediately., We never demand prepaid cards, • Scammers demand a separate payment to replace or install a utility-related device or meter., If there is a charge related to work on equipment, it will typically be included in your monthly bill or paid prior to installation, Any over payments will be applied to your NorthWestern Energy account and used to cover future charges.

• How much capacity can be provided by wind, solar, storage and demand response?, MT Wind and WY Wind are included in the NW zone and not in the ‘external’ zone. 2018 RESULTS 24 2018 System 2018 Baseline system includes 24 GW of thermal generation, 35 GW of hydro generation, and 7 GW of wind generation • Sources: GENESYS database for NWPCC region and TEPPC anchor dataset for other select NWPP BAAs By 2023, approximately 1,800 MW of coal generation is expected to retire 2018 Loads: 246 TWh/yr, 43 GW peak Resource 2018 Nameplate MW Hydro 1 34,697 Natural Gas 12,181 Coal 10,895 Wind 7,079 Nuclear 1,150 Solar 1,557 Other Hydro 2 524 Biomass 489 Geothermal 80 Demand Response 3 299 Imports 4 2,500 1 Hydro is modeled as energy budgets for each month and does not use nameplate capacity 2 Other hydro is hydro outside NWPCC region 3 Demand Response: max 10 calls, each call max duration = 4 hours 4 Imports are zero for summer months (Jun, Jul, Aug, Sep) except during off-peak hours NOTE: Storage assumed to be insignificant in the current, system Hydro 44% Natural Gas 18% Coal 16% Wind 10% Nuclear 2% Solar 2% Other Hydro 1% Biomass 1% Demand Response 2% Imports 4% 24 Capacity Mix % 25 2018 system is in very tight load-resource balance A planning reserve margin of 12% is required to meet 1-in-10 reliability standard The 2018 system does not meet 1-in-10 reliability standard (2.4 hrs., is greater than zero When net load is less than zero storage always charges When net load is greater than zero, storage charges from dispatchable generation if state of charge is below 100% (or other user specified threshold) 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 M W BTM Solar Solar Wind Hydro Storage Discharge Storage Charge Gross Load Net Load After Storage Charge Discharge Available Dispatchable Resources • Coal • Gas • Nuclear • Geothermal 109 Demand Response 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 M W BTM Solar Solar Wind Hydro Storage Discharge Storage Charge Gross Load Net Load After Storage Charge Discharge Available Dispatchable Resources • Coal • Gas • Nuclear • Geothermal • Demand Response Demand response is treated as the dispatchable resource of last resort – if net load after storage is greater than available dispatchable resources it is added to available resources Each DR resource, has prescribed number of hours with a limited quantity of available calls per year 110 Calculating Loss of Load Any residual load that cannot be served from all available resource is counted as lost load Loss of load expectation (LOLE) is the number of hours of lost load per year 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 M W BTM Solar Solar Wind Hydro Storage Discharge Storage Charge Gross Load Net Load After Storage Charge Discharge Loss of Load Available Dispatchable Resources • Coal • Gas • Nuclear • Geothermal • Demand Response Thank You!

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.

Demand-Side Management (10:10-10:40) • Current offerings • Demand Response at other utilities (Diego Rivas) • Break (5 min) 4., Va r iable costs Dispatchability Ability to control timing and level of generation Flexibility Ability to modify production in response to prices/load/other gen Speed of ramp-up and down We ather-Dependence Va r iable energy resource Energy Limitations Duration of charge/discharge (ride-through) Carbon Intensity (CO2/MWh) Emissions from burning of fossil fuels Relative Strengths of Supply-Side Re s ources 9 Note: Illustrative example of relative strengths only., Reduction in perfect capacity to return to original system LOLE = ELCC (MW) L O L E Source: E3 Reliability Metrics 14 Reliability Metric Units Definition Dimension Captured Example Reliability Ta rget Loss-of-Load Probability (LOLP) % Probability of system demand exceeding available generation capacity over a year Frequency Expected Unserved Energy (EUE) MWh /year Average quantity of unserved energy over a year Magnitude 16 MWh/year (equivalent to 0.1 LOLE for NWE system) Loss-of-Load Hours (LOLH) hours /year Average number of hours per year where system demand exceeded available generation capacity Duration 2.4 hours/year Loss-of-Load Expectation (LOLE) days/ year Average number of days with loss of load (at least once during the day) Frequency 0.1 day/year 1., Management 19 Demand-Side Management – Current Offe r ings 20 Discussion, see www., N orthWe sternEnergy. com/Eplus Demand-Side Management 21 Demand Response at other utilities – Diego Rivas NorthWe ste r n ’s E x i st i n g Re s o u rc e Po r t fo l i o 22 Current Po r t fo l io Timeline 23 Online Thermal 24 Thermal/Coal Facility Capacity (MW) Expiration Peak Load Contribution (MW) Colstrip 222 Rate Based 203.7 Yellowstone Energy Limited Partnership (BGI) 52 12/31/2028 50.4 Colstrip Energy Limited Partnership 35 6/30/2024 34.0 Total 309 288 Thermal/Natural Gas Facility Capacity (MW) Expiration Peak Load Contribution (MW) Basin Creek 52 6/30/2036 49.4 DGGS 1 50 Rate Based 145.5 DGGS 2 50 Rate Based DGGS 3 50 Rate Based Total 202 197 DGGS 25 Online Hydro 26 Hydro Facility Capacity (MW) Expiration Peak Load Contribution (MW) Thompson Falls 94 Rate Based 56.4 Cochrane 62 Rate Based 37.2 Ryan 71 Rate Based 42.6 Rainbow 64 Rate Based 38.4 Holter 53 Rate Based 31.8 Morony 49 Rate Based 29.4 Black Eagle 21 Rate Based 12.6 Hauser 19 Rate