FERC Form

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.


(1)Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 764,200 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.

The Financial Statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System of Accounts and published accounting releases. The preparation of financial statements in conformity with the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates.

Management has evaluated the impact of events occurring after December 31, 2022 up to February 17, 2023, the date that NorthWestern's financial statements prepared in accordance with the accounting principles generally accepted in the United States of America (GAAP) were issued, and has updated such evaluation for disclosure purposes through March 6, 2023. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.


(2)Significant Accounting Policies

Financial Statement Presentation

The financial statements are presented on the basis of the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than GAAP. This report differs from GAAP due to FERC requiring the presentation of subsidiaries on the equity method of accounting, which differs from Accounting Standards Codification (ASC) 810, Consolidation. ASC 810 requires that all majority-owned subsidiaries be consolidated (see Note 4). The other significant differences consist of the following:

•Earnings per share and footnotes for revenue from contracts with customers, segment and related information, and quarterly financial data (unaudited) are not presented;

•Removal and decommissioning costs of generation, transmission and distribution assets are reflected in the Balance Sheets as a component of accumulated depreciation of $502.2 million and $479.3 million as of December 31, 2022 and December 31, 2021, respectively, in accordance with regulatory treatment as compared to regulatory liabilities for GAAP purposes;

•Goodwill is reflected in the Balance Sheets as a utility plant adjustments of $357.6 million as of December 31, 2022 and December 31, 2021, respectively, in accordance with regulatory treatment, as compared to goodwill for GAAP purposes (see Note 8);

•The write-down of plant values associated with the 2002 acquisition of the Montana operations is reflected in the Balance Sheets as a component of accumulated depreciation of $147.6 million for December 31, 2022 and December 31, 2021, respectively, in accordance with regulatory treatment as compared to plant for GAAP purposes;

•The current portion of gas stored underground is reflected in the Balance Sheets as current and accrued assets, as compared to inventory for GAAP purposes;

•Operating lease right of use assets are reflected in the Balance Sheets as capital leases of $1.3 million and $2.1 million as of December 31, 2022 and December 31, 2021, respectfully, in accordance with regulatory treatment, as compared to non-current assets for GAAP purposes;

•Operating lease liabilities are reflected in the Balance Sheets as current and long term obligations under capital leases of $1.3 million and $2.1 million as of December 31, 2022 and December 31, 2021, respectfully, in accordance with regulatory treatment, as compared to accrued expenses and long term liabilities for GAAP purposes;

•Unamortized debt expense is classified in the Balance Sheets as deferred debits in accordance with regulatory treatment, as compared to long-term debt for GAAP purposes;

•Current and long-term debt is classified in the Balance Sheets as all long-term debt in accordance with regulatory treatment, while current and long-term debt are presented separately for GAAP reporting;

•The current portion of the provision for injuries and damages and the expected insurance proceeds receivable related to the provision for injuries and damages are reported as a current liability for GAAP purposes, as compared to a non-current liability for FERC purposes;

•Accumulated deferred tax assets and liabilities are classified in the Balance Sheets as gross non-current deferred debits and credits, respectively, while GAAP presentation reflects a net non-current deferred tax liability;

•Stranded tax effects associated with the Tax Cuts and Jobs Act are included in accumulated other comprehensive income (AOCI) in accordance with regulatory treatment, while included in retained earnings for GAAP purposes;

•Uncertain tax positions related to temporary differences are classified in the Balance Sheets within the deferred tax accounts in accordance with regulatory treatment, as compared to other noncurrent liabilities for GAAP purposes. In addition, interest related to uncertain tax positions is recognized in interest expense in accordance with regulatory treatment, as compared to income tax expense for GAAP purposes;

•Net periodic benefit costs and net periodic post retirement benefit costs are reflected in operating expense for FERC purposes, as compared to the GAAP presentation, which reflects the current service costs component of the net periodic benefit costs in operating expenses and the other components outside of income from operations. In addition, only the service cost component of net periodic benefit cost is eligible for capitalization for GAAP purposes, as compared to the total net periodic benefit costs for FERC purposes;

•Regulatory assets and liabilities are reflected in the Balance Sheets as non-current items, while current and non-current amounts are presented separately for GAAP;

•Unbilled revenue is reflected in the Balance Sheets in Accrued utility revenues in accordance with regulatory treatment, as compared to Accounts receivable, net for GAAP purposes;

•Implementation costs associated with cloud computing arrangements are reflected on the Balance Sheets as Miscellaneous Intangible Plant in accordance with regulatory treatment, as compared to Other current assets for GAAP purposes. Additionally, these cash outflows are presented within investing activities cash outflows in the Statement of Cash Flows in accordance with regulatory treatment, as compared to operating activities cash outflows for GAAP purposes; and

•GAAP revenue differs from FERC revenue primarily due to the equity method of accounting as discussed above, netting of electric purchases and sales for resale in revenue for the GAAP presentation as compared to a gross presentation for FERC purposes (with the exception of those transactions in a regional transmission organization (RTO)), the netting of RTO transmission transactions for the GAAP presentation as compared to a gross presentation for FERC purposes, and the classification of regulatory amortizations in revenue for GAAP purposes as compared to expense for FERC purposes.

The following table reconciles GAAP revenues to FERC revenues by segment for the twelve months ended December 31, 2022 and 2021 (in millions):


	Twelve Months Ended December 31, 2022
	Total		Electric		Natural Gas		Other

GAAP Revenues	$	1,477.8	$	1,106.5	$	371.3	$	—
Revenue from equity investments	(3.0)		—		(3.0)		—
Grossing revenues / power purchases	57.8		57.8		—		—
Regulatory amortizations	(14.4)		(44.0)		29.6		—
Other	6.0		6.9		(1.9)		1.0
FERC Revenues	$	1,524.2	$	1,127.2	$	396.0	$	1.0


	Twelve Months Ended December 31, 2021
	Total		Electric		Natural Gas		Other

GAAP Revenues	$	1,372.3	$	1,052.2	$	320.1	$	—
Revenue from equity investments	(3.0)		—		(3.0)		—
Grossing revenues / power purchases	38.1		38.1		—		—
Regulatory amortizations	(42.7)		(32.1)		(10.6)		—
Other	4.0		4.6		(1.3)		0.7
FERC Revenues	$	1,368.7	$	1,062.8	$	305.2	$	0.7

Use of Estimates

The preparation of financial statements in conformity with the regulatory basis of accounting requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncertain tax position reserves, asset retirement obligations, regulatory assets and liabilities, allowances for uncollectible accounts, our Qualifying Facilities liability, environmental liabilities, unbilled revenues and actuarially determined benefit costs and liabilities. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results.

Revenue Recognition

The Company recognizes revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred.

Cash Equivalents

We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable, Net

Accounts receivable are net of allowances for uncollectible accounts of $2.5 million and $2.3 million at December 31, 2022 and December 31, 2021, respectively. Unbilled revenues were $117.4 million and $98.1 million at December 31, 2022 and December 31, 2021, respectively.

Inventories

Inventories are stated at average cost. Inventory consisted of the following (in thousands):


	December 31,
	2022		2021
Fuel stock	$	7,725	$	7,510
Plant materials and operating supplies	71,154		53,539
Gas stored underground (including the non-current portion reflected in utility plant)	63,933		55,019
Total Inventories	$	142,812	$	116,068

Regulation of Utility Operations

Our regulated operations are subject to the provisions of ASC 980, Regulated Operations. Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers.

Our Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (Accumulated Provision for Rate Refunds).

If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Statements of Income at that time. This would result in a charge to earnings and AOCI, net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets.

Derivative Financial Instruments

We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging. All derivatives are recognized in the Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Statements of Cash Flows, depending on the underlying nature of the hedged items. As of December 31, 2022, the only derivative instruments we have qualify for the normal purchases and normal sales exception.

Revenues and expenses on contracts that are designated as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 9 - Risk Management and Hedging Activities, for further discussion of our derivative activity.

Utility Plant

Utility Plant stated at original cost, including contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision and similar overhead items. All expenditures

for maintenance and repairs of utility plant are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under finance lease, which are stated at the present value of minimum lease payments.

AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to net interest charges, while the equity component is included in other income. This rate averaged 6.4% and 6.6% for Montana for 2022 and 2021, respectively. This rate averaged 6.4% for South Dakota for 2022 and 2021. AFUDC capitalized totaled $20.2 million and $15.9 million for the years ended December 31, 2022, 2021 respectively, for Montana and South Dakota combined.

We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from 2 to 96 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 2.8% for 2022 and 2021

Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in accumulated depreciation.

Pension and Postretirement Benefits

We have liabilities under defined benefit retirement plans and a postretirement plan that offers certain health care and life insurance benefits to eligible employees and their dependents. The costs of these plans are dependent upon numerous factors, assumptions and estimates, including determination of discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize.

Income Taxes

We follow the liability method in accounting for income taxes. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized.

Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Statement of Income and provision for income taxes.

Environmental Costs

We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates.

Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.

Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost.

Supplemental Cash Flow Information


	Twelve Months Ended December 31,
	2022		2021
	(in thousands)
Cash paid for:
Income taxes	$	4,707	$	4,330
Interest	95,400		87,221
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	64,758		29,034
NMTC debt extinguishment included in other noncurrent assets(1)	—		18,169
NMTC debt extinguishment included in utility plant(1)	—		6,594
NMTC debt extinguishment included in long-term debt(1)	—		1,259

(1) See Note 12 - Long-Term Debt for further information regarding this non-cash transaction.

The following table provides a reconciliation of cash, working funds, other special funds, and special deposits reported within the Balance Sheets that sum to the total of the same such amounts shown in the Statements of Cash Flows (in thousands):


	December 31,
	2022		2021
Cash	$	8,029	$	2,301
Working funds	23		23
Special deposits	12,762		14,658
Total shown in the Statement of Cash Flows	$	20,814	$	16,982

Special deposits consist primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.

Accounting Standards Issued

At this time, we are not expecting the adoption of recently issued accounting standards to have a material impact to our financial condition, results of operations, and cash flows.


(3)Regulatory Matters

Montana Rate Review

On August 8, 2022, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates of $171.0 million and $23.0 million, respectively, detailed as follows:


Requested Revenue Increase (in millions)
	Electric	Natural Gas
Base Rates	$91.8	$20.2
Power Cost & Credit Mechanism (PCCAM)(1)	$68.1	n/a
Property Tax (tracker true-up)(1)	$11.1	$2.8
Total	$171.0	$23.0

(1) These items are flow-through costs, which represent approximately 42% of the requested electric and natural gas revenue increase.

Our electric request is based on a return on equity of 10.60% with a forecasted 2022 rate base of $2.8 billion and a capital structure of 51.98% debt and 48.02% equity. Our natural gas request is based on a return on equity of 10.60% with a forecasted 2022 rate base of $575.3 million and a capital structure of 51.98% debt and 48.02% equity.

Within this rate review filing we requested an increase to the Power Cost and Credit Mechanism (PCCAM) base rate (PCCAM Base rate) of $68.1 million, as well as structural revisions to the PCCAM mechanism to provide customers with prices that better reflect the cost of services received. We also proposed to implement a revised electric only pilot for the Fixed Cost Recovery Mechanism (FCRM) beginning July 1, 2023, or alternatively to terminate the FCRM. Our rate review filing also includes proposals for more timely cost recovery beyond the test period, including critical reliability resources, such as the Yellowstone County Generating Station, our Enhanced Wildfire Mitigation plan, and business technology maintenance costs.

On September 28, 2022, the MPSC approved the recommendations of the MPSC Staff for interim rates, subject to refund, which increased base electric rates $29.4 million, PCCAM Base rates $61.1 million, and base natural gas rates $1.7 million, effective October 1, 2022.

A hearing is scheduled to commence on April 11, 2023. Interim rates will remain in effect on a refundable basis until the MPSC issues a final order.

Montana Community Renewable Energy Projects (CREPs)

We were required to acquire, as of December 31, 2020, approximately 65 MW of CREPs. While we made progress towards meeting this obligation by acquiring approximately 50 MW of CREPs, we were unable to acquire the remaining MWs required for various reasons, including the fact that proposed projects fail to qualify as CREPs or do not meet the statutory cost cap. The MPSC granted us waivers for 2012 through 2016. The validity of the MPSC’s action as it related to waivers granted for 2015 and 2016 has been challenged legally and was fully briefed before the Montana Supreme Court.

On May 14, 2021, the Montana Governor signed a bill that eliminated the state's Renewable Portfolio Standard, including repeal of the CREP requirement. We notified the Montana Supreme Court of the repeal. We also dismissed our pending application filed with the MPSC for a waiver from full compliance for years 2017 through 2020.

On September 7, 2021, the Montana Supreme Court remanded the case challenging the 2015 and 2016 waivers to the District Court to determine whether the repeal of the CREP requirement made the petition moot. On May 9, 2022, the District Court imposed a $2.5 million penalty against us, payable to the Universal Low Income Assistance Fund in Montana, in connection with a petition filed by the MEIC challenging the MPSC's decision granting our waiver requests from CREP

compliance in 2015 and 2016. The expense associated with this penalty was accrued for within our 2022 results. We filed an appeal with the Montana Supreme Court and that appeal is now fully briefed.


(4)Equity Investments

The following table presents our equity investments reflected in the investments in subsidiary companies on the Balance Sheets (in thousands):


	December 31,
	2022		2021
Havre Pipeline Company, LLC	$	11,399	$	12,130
Canadian Montana Pipeline Corporation	4,984		4,867
NorthWestern Services, LLC	2,091		2,065
NorthWestern Energy Solutions, Inc.	5,738		4,126
Risk Partners Assurance, Ltd.	1,132		1,190
Total Investments in Subsidiary Companies	$	25,344	$	24,378


(5)Regulatory Assets and Liabilities

We prepare our Financial Statements in accordance with the provisions of ASC 980, as discussed in Note 2 - Significant Accounting Policies. Pursuant to this guidance, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded based on management's assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. Of these regulatory assets and liabilities, energy supply costs, excluding the Montana PCCAM, are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods.


	Note Reference	Remaining Amortization Period	December 31,
			2022		2021
			(in thousands)
Flow-through income taxes	14	Plant Lives	$	509,038	$	464,664
Pension	16	See Note 16	87,965		98,336
Excess deferred income taxes	14	Plant Lives	54,364		60,813
Employee related benefits	16	See Note 16	27,920		21,648
State & local taxes & fees		1 Year	15,643		6,514
Environmental clean-up	19	Undetermined	10,963		11,262
Other		Various	23,191		21,912
Total Regulatory Assets			$	729,084	$	685,149
Excess deferred income taxes	14	Plant Lives	148,989		158,047
Unbilled revenue		1 Year	11,536		16,430
Gas storage sales		17 years	7,046		7,466
State & local taxes & fees		1 Year	2,327		3,021
Environmental clean-up and other		1 Year	1,503		693
Total Regulatory Liabilities			$	171,401	$	185,657

Income Taxes

Flow-through income taxes primarily reflect the effects of plant related temporary differences such as flow-through of depreciation, repairs related deductions, and removal costs that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse. Excess deferred income tax assets and liabilities are recorded as a result of the Tax Cuts and Jobs Act and will be recovered or refunded in future rates. See Note 14 - Income Taxes for further discussion.

Pension and Employee Related Benefits

We recognize the unfunded portion of plan benefit obligations in the Balance Sheets, which is remeasured at each year end, with a corresponding adjustment to regulatory assets/liabilities as the costs associated with these plans are recovered in rates. The MPSC allows recovery of pension costs on a cash funding basis. The portion of the regulatory asset related to our Montana pension plan will amortize as cash funding amounts exceed accrual expense under GAAP. The SDPUC allows recovery of pension costs on an accrual basis. The MPSC allows recovery of postretirement benefit costs on an accrual basis.

State & Local Taxes & Fees (Montana Property Tax Tracker)

Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover the increase in rates, less the amount allocated to FERC jurisdictional customers and net of the related income tax benefit.

Environmental Clean-up

Environmental clean-up costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss the specific sites and clean-up requirements further in Note 19 - Commitments and Contingencies. Environmental clean-up costs are typically recoverable in customer rates when they are actually incurred. When cost projections become known and measurable, we coordinate with the appropriate regulatory authority to determine a recovery period.

Gas Storage Sales

A regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base.

Unbilled Revenue

In accordance with regulatory guidance in South Dakota, we recognize revenue when it is billed. Accordingly, we record a regulatory liability to offset unbilled revenue.


(6)Utility Plant

The following table presents the major classifications of our net utility plant (in thousands):


	December 31,
	2022		2021 (1)
	(in thousands)
Electric Plant	$	5,286,650	$	4,929,211
Natural Gas Plant	1,311,436		1,192,066
Plant acquisition adjustment	686,328		686,328
Common and Other Plant	306,866		276,481
Construction work in process	300,649		284,729
Total utility plant	7,891,929		7,368,815
Less accumulated depreciation	(2,786,712)		(2,648,396)
Net utility plant	$	5,105,217	$	4,720,419

(1) The December 31, 2021 balances reported above have been reclassified to conform with the December 31, 2022 presentation of major classifications of property, plant and equipment. The reclassification has no impact on the presentation of total property, plant and equipment. These reclassifications were done in an effort to better convey the nature of these balances.

Net utility plant under capital (finance) lease were $7.2 million and $9.2 million as of December 31, 2022 and 2021, respectively, which included $7.0 million and $9.0 million as of December 31, 2022 and 2021, respectively, related to a long-term power supply contract with the owners of a natural gas fired peaking plant, which has been accounted for as a finance lease.

Jointly Owned Electric Generating Plant

We have an ownership interest in four base-load electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the

capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Statements of Income. The participants each finance their own investment.

On January 16, 2023, we entered into a definitive agreement (Agreement) with Avista Corporation (Avista) to acquire Avista's 15 percent interest in each of Units 3 and 4 at the Colstrip Generating Station, a coal-fired, base-load electric generation facility located in Colstrip, Montana. As noted in the table below, we currently have a 30 percent interest in Unit 4. The Agreement provides that the purchase price will be $0 and that we will acquire Avista's interest effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the agreement. Under the terms of this Agreement, we will be responsible for operating costs starting on January 1, 2026; while Avista will retain responsibility for its pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommission and demolition costs associated with the existing facilities that comprise Avista's interest.

The Agreement contains customary representations and warranties, covenants, and indemnification obligations, and the Agreement is subject to customary conditions and approvals, including approval from the FERC. Closing also is conditioned on our ability to enter into a new coal supply agreement for Colstrip by December 31, 2024. Such coal supply agreement must provide a sufficient amount of coal to Colstrip to permit the generation of electric power by the maximum permitted capacity of the interest in Colstrip then held by us during the period from January 1, 2026 through, December 31, 2030.

Either party may terminate the Agreement if any requested regulatory approval is denied or if the closing has not occurred by December 31, 2025 or if any law or order would delay or impair closing. The Agreement may be subject to the exercise by other Colstrip owners of a right of first refusal set forth in the O&O Agreement. Should any other owners exercise such rights, we intend to exercise our right of first refusal under the O&O Agreement to the fullest extent permitted, and Avista has agreed that it will not exercise its right of first refusal.

Information relating to our ownership interest in these facilities is as follows (in thousands):


	Big Stone (SD)			Neal #4 (IA)			Coyote (ND)			Colstrip Unit 4 (MT)
December 31, 2022
Ownership percentages	23.4		%	8.7		%	10.0		%	30.0		%
Plant in service	$	155,567		$	63,032		$	51,796		$	326,584
Accumulated depreciation	46,748			39,077			42,465			122,938
December 31, 2021
Ownership percentages	23.4		%	8.7		%	10.0		%	30.0		%
Plant in service	$	154,375		$	62,865		$	51,652		$	324,433
Accumulated depreciation	45,895			37,749			41,918			114,830


(7)Asset Retirement Obligations

We are obligated to dispose of certain long-lived assets upon their abandonment. We recognize a liability for the legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets, which increases our utility plant and asset retirement obligations (ARO). The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the ARO is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the rate making process. We record regulatory assets and liabilities for differences in timing of asset retirement costs recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers.

Our AROs relate to the reclamation and removal costs at our jointly-owned coal-fired generation facilities, U.S. Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments, our obligation to plug and abandon oil and gas wells at the end of their life, and to remove all above-ground wind power facilities and restore the soil surface at the end of their life. The following table presents the change in our ARO (in thousands):


	December 31,
	2022		2021
Liability at January 1,	$	40,631	$	45,355
Accretion expense	1,853		2,233
Liabilities incurred	—		—
Liabilities settled	(4,004)		(2,906)
Revisions to cash flows	2,414		(3,935)
Liability at December 31,	$	40,894	$	40,747

During the twelve months ended December 31, 2022 our ARO liability decreased $4.0 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facilities and natural gas pipeline segments. Additionally, during the twelve months ended December 31, 2022, our ARO liability increased $2.4 million related to changes in both the timing and amount of retirement cost estimates.

In addition, we have identified removal liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. We also identified AROs associated with our hydroelectric generating facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Financial Statements.

We collect removal costs in rates for certain transmission and distribution assets that do not have associated AROs. Generally, the accrual of future non-ARO removal obligations is not required; however, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.


(8)Utility Plant Adjustments

We completed our annual utility plant adjustments impairment test as of April 1, 2022 and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.


(9)Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines.

In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale (NPNS); cash flow hedge; fair value hedge; and mark-to-market.

Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Normal Purchases and Normal Sales

We have applied the NPNS scope exception to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Financial Statements at December 31, 2022 and 2021. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Credit Risk

Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.

We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The

agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.

Interest Rate Swaps Designated as Cash Flow Hedges

We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCI. We reclassify these gains from AOCI into interest on long term debt during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):

Cash Flow Hedges

Location of Amount Reclassified from AOCI to Income

Amount Reclassified from AOCI into Income during the Year Ended December 31, 2021

Interest rate contracts

Interest on long-term debt

612

A pre-tax loss of approximately $13.4 million is remaining in AOCI as of December 31, 2022, and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCI into interest expense during the next twelve months. These amounts relate to terminated swaps.


(10)Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

•Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;

•Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and

•Level 3 – Significant inputs that are generally not observable from market activity.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Due to the short-term nature of cash and cash equivalents, accounts receivable, net, and accounts payable, the carrying amount of each such item approximates fair value.

The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 9 - Risk Management and Hedging Activities for further discussion.

We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.


December 31, 2022	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
Special deposits	$	12,762	$	—	$	—	$	—	$	12,762
Rabbi trust investments	20,895		—		—		—		20,895
Total	$	33,657	$	—	$	—	$	—	$	33,657

December 31, 2021
Special deposits	$	14,658	$	—	$	—	$	—	$	14,658
Rabbi trust investments	18,234		—		—		—		18,234
Total	$	32,892	$	—	$	—	$	—	$	32,892

Special deposits represent amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets.

Financial Instruments

The estimated fair value of financial instruments is summarized as follows (in thousands):


	December 31, 2022				December 31, 2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	2,629,660	$	2,327,478	$	2,552,660	$	2,838,518

The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.


(11)Unsecured Credit Facilities

Credit Facility

On May 18, 2022, we amended our existing $425 million credit facility to, among other things, change the Eurodollar rate to the secured overnight financing rate as administered by the Federal Reserve Bank of New York (SOFR) and extend the maturity date of the facility from September 2, 2023 to May 18, 2027. The amended and restated credit facility (the Primary Credit Facility) maintains the same capacity at $425 million and uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size of the facility by up to an additional $75 million. The Primary Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points.

On October 28, 2022, we entered into a $100 million Credit Agreement (the Additional Credit Facility) to supplement our existing $425 million revolving credit facility. The Additional Credit Facility has a maturity date of April 28, 2024. The Additional Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points.

On March 25, 2022, we amended our existing $25 million swingline credit facility (the Swingline Facility) to, among other things, change the Eurodollar rate to the secured overnight financing rate as administered by the Federal Reserve Bank of New York (SOFR) and extend the maturity date of the facility from March 27, 2023 to March 27, 2024. The Swingline Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a margin of 90.0 basis points, or (b) a base rate, plus a margin of 12.5 basis points.

Commitment fees for the unsecured revolving lines of credit were $0.1 million and $0.4 million for the years ended December 31, 2022 and 2021.

The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions):


	2022		2021
Unsecured revolving line of credit, expiring May 2027	$	425.0	$	425.0
Unsecured revolving line of credit, expiring April 2024	100.0		—
Unsecured revolving line of credit, expiring March 2024	25.0		25.0
	550.0		450.0

Amounts outstanding at December 31:
SOFR borrowings	450.0		—
Eurodollar borrowings	—		373.0
Letters of credit	—		—
	450.0		373.0

Net availability as of December 31	$	100.0	$	77.0

The Credit Facility includes covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facility also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the Credit Facility; however, a default on the Credit Facility would not trigger a default on the South Dakota or Montana First Mortgage Bonds.


(12)Long-Term Debt

Long-term debt consisted of the following (in thousands):


		December 31,
	Due	2022		2021
Unsecured Debt:
Unsecured Revolving Line of Credit	2027	$	425,000	$	—
Unsecured Revolving Line of Credit	2024	25,000		—
Unsecured Revolving Line of Credit	2023	—		373,000
Secured Debt:
Mortgage bonds—
South Dakota—5.01%	2025	64,000		64,000
South Dakota—4.15%	2042	30,000		30,000
South Dakota—4.30%	2052	20,000		20,000
South Dakota—4.85%	2043	50,000		50,000
South Dakota—4.22%	2044	30,000		30,000
South Dakota—4.26%	2040	70,000		70,000
South Dakota—3.21%	2030	50,000		50,000
South Dakota—2.80%	2026	60,000		60,000
South Dakota—2.66%	2026	45,000		45,000
Montana—5.71%	2039	55,000		55,000
Montana—5.01%	2025	161,000		161,000
Montana—4.15%	2042	60,000		60,000
Montana—4.30%	2052	40,000		40,000
Montana—4.85%	2043	15,000		15,000
Montana—3.99%	2028	35,000		35,000
Montana—4.176%	2044	450,000		450,000
Montana—3.11%	2025	75,000		75,000
Montana—4.11%	2045	125,000		125,000
Montana—4.03%	2047	250,000		250,000
Montana—3.98%	2049	150,000		150,000
Montana—3.21%	2030	100,000		100,000
Montana—1.00%	2024	100,000		100,000
Pollution control obligations—
Montana—2.00%	2023	144,660		144,660
Total Long-Term Debt		$	2,629,660	$	2,552,660

Secured Debt

First Mortgage Bonds and Pollution Control Obligations

The South Dakota First Mortgage Bonds are a series of general obligation bonds issued under our South Dakota indenture. These bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets.

The Montana First Mortgage Bonds and Montana Pollution Control Obligations are secured by substantially all of our Montana electric and natural gas assets.

In March 2021, we issued and sold $100.0 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00 percent maturing on March 26, 2024. The net proceeds were used to repay in full our outstanding $100.0 million term loan that was due April 2, 2021. We may redeem some or all of the bonds at any time in whole, or from time to time in part, at our option, on or after March 26, 2022, at a redemption price equal to 100% of the principal amount of the bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding, the redemption date. The bonds are secured by our electric and natural gas assets in Montana and Wyoming.

As of December 31, 2022, we were in compliance with our financial debt covenants.

Other Long-Term Debt

In July 2021, our two loans totaling $27.0 million associated with the New Market Tax Credit (NMTC) financing agreement were extinguished. These loans were satisfied with our $18.2 million investment in the entities created in relation to the NMTC transaction, investor forgiveness of $7.9 million for substantially all of the benefits derived from the tax credits, and cash payment of $0.9 million. In accordance with our last rate case filing in the state of Montana, the portion of the loan forgiven, less unamortized debt issuance costs of $1.3 million, was recorded as a reduction to the cost of the office building associated with the NMTC financing agreement. This cash payment is reflected within the financing activities section of our Statement of Cash Flows for the year ended December 31, 2021; however, the remaining reduction to Long-term debt, Other investments, and Utility plant are non-cash financing activities that are not reflected within our Statement of Cash Flows for the year ended December 31, 2021.

Maturities of Long-Term Debt

The aggregate minimum principal maturities of long-term debt during the next five years are $144.7 million in 2023, $125.0 million in 2024, $300.0 million in 2025, $105.0 million in 2026 and $425.0 million in 2027.


(13)Related Party Transactions

Accounts receivable from and payables to associated companies primarily include intercompany billings for direct charges, overhead, and income tax obligations. The following table reflects our accounts receivable from and accounts payable to associated companies (in thousands):


	December 31,
	2022		2021
Accounts Receivable from Associated Companies:
Havre Pipeline Company, LLC	$	3,201	$	2,729
NorthWestern Energy Solutions, Inc.	16		71
Risk Partners Assurance, Ltd.	(74)		18
	$	3,143	$	2,818

Accounts Payable to Associated Companies:
Canadian Montana Pipeline Corporation	$	2,312	$	2,094
NorthWestern Services, LLC	2,045		1,837
	$	4,357	$	3,931


(14)Income Taxes

Our effective tax rate typically differs from the federal statutory tax rate primarily due to production tax credits and the regulatory impact of flowing through the federal and state tax benefit of repairs deductions and state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable). The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

The components of the net deferred income tax assets and liabilities recognized in our Balance Sheets are related to the following temporary differences (in thousands):


	December 31,
	2022		2021
Production tax credit	$	80,097	$	75,092
Pension / postretirement benefits	19,291		21,435
Customer advances	25,119		21,271
Unbilled revenue	9,440		10,704
Compensation accruals	10,306		10,612
Environmental liability	6,009		5,704
Reserves and accruals	4,015		5,105
Interest rate hedges	3,372		3,158
Other, net	6,295		7,833
Deferred Tax Asset	163,944		160,914
Excess tax depreciation	(455,220)		(431,345)
Flow through depreciation	(104,976)		(92,502)
Goodwill amortization	(91,746)		(91,689)
Regulatory assets and other	(58,065)		(53,896)
Deferred Tax Liability	(710,007)		(669,432)
Deferred Tax Liability, net	$	(546,063)	$	(508,518)

At December 31, 2022, our total production tax credit carryforward was approximately $80.1 million. If unused, our production tax credit carryforwards will expire as follows: $8.9 million in 2036, $11.0 million in 2037, $10.9 million in 2038, $11.5 million in 2039, $13.1 million in 2040, $11.5 million in 2041, and $13.2 million in 2042. We believe it is more likely than not that sufficient taxable income will be generated to utilize these production tax credit carryforwards.

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (in thousands):


	2022		2021
Unrecognized Tax Benefits at January 1	$	32,049	$	33,491
Gross increases - tax positions in prior period	—		293
Gross increases - tax positions in current period	—		—
Gross decreases - tax positions in current period	(1,719)		(1,735)
Lapse of statute of limitations	—		—
Unrecognized Tax Benefits at December 31	$	30,330	$	32,049

Our unrecognized tax benefits include approximately $27.9 million and $28.1 million related to tax positions as of December 31, 2022 and 2021, that if recognized, would impact our annual effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest related to uncertain tax positions in interest expense. As of December 31, 2022, we have accrued $1.4 million for the payment of interest in the Balance Sheets. As of December 31, 2021, we had $0.5 million accrued for the payment of interest.

Tax years 2019 and forward remain subject to examination by the Internal Revenue Service (IRS) and state taxing authorities. During the first quarter of 2023 the IRS commenced a limited scope examination of the Company's 2019 amended federal income tax return.


(15)Comprehensive Income (Loss)

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):


	December 31,
	2022						2021
	Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount		Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount
Foreign currency translation adjustment	$	(8)	$	—	$	(8)	$	(58)	$	—	$	(58)
Reclassification of net income (loss) on derivative instruments	612		(160)		452		614		(162)		452
Postretirement medical liability adjustment	(1,359)		377		(982)		(585)		149		(436)
Other comprehensive income (loss)	$	(755)	$	217	$	(538)	$	(29)	$	(13)	$	(42)

Balances by classification included within AOCI on the Balance Sheets are as follows, net of tax (in thousands):


	December 31,
	2022		2021
Foreign currency translation	$	1,435	$	1,443
Derivative instruments designated as cash flow hedges	(7,675)		(8,127)
Postretirement medical plans	534		1,516
Accumulated other comprehensive loss	$	(5,706)	$	(5,168)

The following table displays the changes in AOCI by component, net of tax (in thousands):


	December 31, 2022
	Year Ended
	Affected Line Item in the Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(8,127)	$	1,516	$	1,443	$	(5,168)
Other comprehensive income before reclassifications						(8)		(8)
Amounts reclassified from AOCI	Interest on long-term debt	452						452
Amounts reclassified from AOCI				(982)				(982)
Net current-period other comprehensive income		452		(982)		(8)		(538)
Ending Balance		$	(7,675)	$	534	$	1,435	$	(5,706)


	December 31, 2021
	Year Ended
	Affected Line Item in the Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(8,579)	$	1,952	$	1,501	$	(5,126)
Other comprehensive income before reclassifications						(58)		(58)
Amounts reclassified from AOCI	Interest on long-term debt	452						452
Amounts reclassified from AOCI				(436)				(436)
Net current-period other comprehensive income		452		(436)		(58)		(42)
Ending Balance		$	(8,127)	$	1,516	$	1,443	$	(5,168)


(16)Employee Benefit Plans

Pension and Other Postretirement Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. The pension plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation plan, and the pension plan for our Montana employees is referred to as the NorthWestern Energy plan, and collectively they are referred to as the Plans. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. The Plans' funded status is recognized as an asset or liability in our Financial Statements. See Note 5 - Regulatory Assets and Liabilities, for further discussion on how these costs are recovered through rates charged to our customers.

Benefit Obligation and Funded Status

Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands):


	Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,
	2022		2021		2022		2021
Change in benefit obligation:
Obligation at beginning of period	$	696,802	$	820,979	$	19,146	$	19,146
Service cost	10,223		12,994		407		407
Interest cost	18,787		18,759		317		317
Actuarial loss	(176,389)		(28,905)		415		415
Settlements(1)	—		(93,488)		—		—
Benefits paid	(27,625)		(33,537)		(2,977)		(2,977)
Benefit Obligation at End of Period	$	521,798	$	696,802	$	17,308	$	17,308
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	$	605,499	$	688,456	$	23,096	$	23,096
Return on plan assets	(144,535)		33,868		3,349		3,349
Employer contributions	8,200		10,200		1,821		1,821
Settlements(1)	—		(93,488)		—		—
Benefits paid	(27,625)		(33,537)		(2,977)		(2,977)
Fair value of plan assets at end of period	$	441,539	$	605,499	$	25,289	$	25,289
Funded Status	$	(80,259)	$	(91,303)	$	7,981	$	7,981

Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	7,195		8,297		11,914		11,914
Total Assets	7,195		8,297		11,914		11,914
Current liability	(11,200)		(11,200)		(1,575)		(1,575)
Noncurrent liability	(76,254)		(88,400)		(2,358)		(2,358)
Total Liabilities	(87,454)		(99,600)		(3,933)		(3,933)
Net amount recognized	$	(80,259)	$	(91,303)	$	7,981	$	7,981

Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	—		—		(116)		1,870
Net actuarial loss	(54,383)		(62,448)		(3,123)		1,366
Amounts recognized in AOCI consist of:
Prior service cost	—		—		—		(95)
Net actuarial gain	—		—		1,046		2,500
Total	$	(54,383)	$	(62,448)	$	(2,193)	$	5,641

(1) In December 2021, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 1,062 NorthWestern Energy Pension Plan participants. We purchased the contract with $93.5 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2022. This transaction settled $93.5 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2021, we recorded a non-cash, non-operating settlement charge of $11.3 million. This charge is recorded within operating expenses, net on the Statements of Income. As discussed within Note 5 – Regulatory Assets and Liabilities, this charge was deferred as a regulatory asset on the Balance Sheets, with a corresponding decrease to operating expense on the Statements of Income.

The actuarial gain/loss is primarily due to the change in discount rate assumption and actual asset returns compared with expected amounts. The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions):


	NorthWestern Energy Pension Plan
	December 31,
	2022		2021
Projected benefit obligation	$	474.9	$	636.3
Accumulated benefit obligation	474.9		636.3
Fair value of plan assets	388.7		537.9

_____________________

As of December 31, 2022, the fair value of the NorthWestern Corporation pension plan assets exceed the total projected and accumulated benefit obligation and are therefore excluded from this table.

Net Periodic Cost (Credit)

The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands):


	Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,
	2022		2021		2022		2021
Components of Net Periodic Benefit Cost
Service cost	$	10,223	$	12,994	$	351	$	407
Interest cost	18,787		18,759		359		327
Expected return on plan assets	(24,173)		(27,061)		(1,047)		(919)
Amortization of prior service cost (credit)	—		—		(1,891)		(1,835)
Recognized actuarial loss (gain)	383		6,536		(897)		(898)
Settlement loss recognized(1)	—		11,291		—		—
Net Periodic Benefit Cost (Credit)	$	5,220	$	22,519	$	(3,125)	$	(2,918)

Regulatory deferral of net periodic benefit cost(2)	2,307		(13,308)		—		—
Previously deferred costs recognized(2)	—		—		292		709
Amount Recognized in Income	$	7,527	$	9,211	$	(2,833)	$	(2,209)

_________________________

(1) Settlement loss is related to partial annuitization of NorthWestern Energy Pension Plan effective December 1, 2021.

(2) Net periodic benefit costs for pension and postretirement benefit plans are recognized for financial reporting based on the authorization of each regulatory jurisdiction in which we operate. A portion of these costs are recorded in regulatory assets and recognized in the Statements of Income as those costs are recovered through customer rates.

For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years.

Actuarial Assumptions

The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2022 and 2021. The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past

experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets. During 2022, the plan's actuary conducted an experience study to review five years of plan experience and update these assumptions.

On an annual basis, we set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The increase in the discount rate during 2022 decreased our projected benefit obligation by approximately $179.2 million.

In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Based on the target asset allocation for our pension assets and future expectations for asset returns, we increased our long term rate of return on assets assumption for NorthWestern Energy Pension Plan to 6.44 percent and increased our assumption on the NorthWestern Corporation Pension Plan to 4.83 percent for 2023.

The weighted-average assumptions used in calculating the preceding information are as follows:


	Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,
	2022		2021		2022		2021
Discount rate	5.20	%	2.65-2.75	%	5.15-5.20	%	2.35-2.40	%
Expected rate of return on assets	2.66-4.26		3.01-4.17		4.23		4.08
Long-term rate of increase in compensation levels (non-union)	4.00		2.84		4.00		2.84
Long-term rate of increase in compensation levels (union)	4.00		2.00		4.00		2.00
Interest crediting rate	3.30-6.00		3.30-6.00		N/A		N/A

The postretirement benefit obligation is calculated assuming that health care costs increase by a 5.00 percent fixed rate. The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation.

Investment Strategy

Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, Prudent Man Rule of the Employee Retirement Income Security Act of 1974 and liability-based considerations. Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following:

•Each plan should be substantially invested as long-term cash holdings reduce long-term rates of return;

•Pension Plan portfolio risk is described by volatility in the funded status of the Plans;

•It is prudent to diversify each plan across the major asset classes;

•Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility;

•Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the pension plans overall funded status, (such assets will be described as Liability Hedging Fixed Income assets);

•Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns;

•Private real estate and broad global opportunistic fixed income asset classes can provide diversification to both equity and liability hedging fixed income investments and that a moderate allocation to each can potentially improve the expected risk-adjusted return for the NorthWestern Energy Pension Plan investments over full market cycles;

•Active management can reduce portfolio risk and potentially add value through security selection strategies;

•A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and

•It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification.

Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocation established, within an allowable range of plus or minus 5 percent, is as follows:


	NorthWestern Energy Pension				NorthWestern Corporation Pension				NorthWestern Energy Health and Welfare
	December 31,				December 31,				December 31,
	2022		2021		2022		2021		2022		2021
Fixed income securities	45.0	%	55.0	%	90.0	%	90.0	%	40.0	%	40.0	%
Non-U.S. fixed income securities	—		4.0		1.0		1.0		—		—
Opportunistic fixed income	5.5		—		—		—		—		—
Global equities	44.0		41.0		9.0		9.0		60.0		60.0
Private real estate	5.5		—		—		—		—		—

The actual allocation by plan is as follows:


	NorthWestern Energy Pension				NorthWestern Corporation Pension				NorthWestern Energy Health and Welfare
	December 31,				December 31,				December 31,
	2022		2021		2022		2021		2022		2021
Cash and cash equivalents	—	%	0.1	%	1.1	%	0.4	%	0.6	%	0.1	%
Fixed income securities	44.5		53.8		88.6		89.5		36.7		33.7
Non-U.S. fixed income securities	—		3.9		0.9		0.9		—		—
Opportunistic fixed income	5.5		—		—		—		—		—
Global equities	43.4		42.2		9.4		9.2		62.7		66.2
Private real estate	6.6		—		—		—
	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. The guidelines allow for a transition to targets over time as assets are reallocated to newly-approved asset classes of opportunistic fixed income and private real estate. Debt securities consist of U.S. and international instruments including emerging markets and high yield instruments, as well as government, corporate, asset backed and mortgage backed securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Equity, real estate and fixed income portfolios may be comprised of both active and passive management strategies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks. We also invest in global equities with exposure to developing and emerging markets. Equity investments may also be diversified across investment styles such as growth and value. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Real estate investments will consist of global equity or debt interests in tangible property consisting of land, buildings, and other improvements in commercial and residential sectors.

Our plan assets are primarily invested in common collective trusts (CCTs), which are invested in equity and fixed income securities. In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class and be invested in a diversified manner and have a minimum of three years of verified investment performance experience or verified portfolio manager investment experience in a particular investment strategy and have management and oversight by an investment advisor registered with the Securities and Exchange Commission (SEC). Investments in a collective investment vehicle are valued by multiplying the investee company’s net asset value per share with the number of units or shares owned at the valuation date. Net asset value per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The funds do not contain any redemption restrictions. The direct holding of NorthWestern Corporation stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted.

Cash Flows

In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements. Additional funding relief was passed in the American Rescue Plan Act of 2021, providing for longer amortization and interest rate smoothing, which we elected to use. We expect to continue to make contributions to the pension plans in 2023 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements.

Due to the regulatory treatment of pension costs in Montana, pension costs for 2022 and 2021 were based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands):


	2022		2021
NorthWestern Energy Pension Plan (MT)	$	7,000	$	9,000
NorthWestern Corporation Pension Plan (SD and NE)	1,200		1,200
	$	8,200	$	10,200

We estimate the plans will make future benefit payments to participants as follows (in thousands):


	Pension Benefits		Other Postretirement Benefits
2023	$	31,014	$	2,520
2024	32,448		2,079
2025	33,904		1,584
2026	34,908		1,511
2027	35,490		1,372
2028-2032	185,939		6,060

Defined Contribution Plan

Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to be contributed to the plan. We contribute various percentage amounts of the employee's gross compensation contributed to the plan. Matching contributions for the years ended December 31, 2022 and 2021 were $12.3 million and $11.8 million, respectively.


(17)Stock-Based Compensation

We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. As of December 31, 2022, there were 655,565 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to five years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control.

We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded.

Performance Unit Awards

Performance unit awards are granted annually under the ECP. These awards vest at the end of the three-year performance period if we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued will vary from 0 percent to 200 percent of the target award, depending on actual company performance relative to the performance goals. These awards contain both market- and performance-based components. The performance goals are

independent of each other and equally weighted, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return (TSR) relative to a peer group.

Fair value is determined for each component of the performance unit awards. The fair value of the earnings per share component is estimated based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:


	2022		2021
Risk-free interest rate	1.82	%	0.19	%
Expected life, in years	3		3
Expected volatility	28.2% to 38.8%		28.2% to 38.5%
Dividend yield	4.5	%	4.3	%

The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest.

A summary of nonvested shares as of and changes during the year ended December 31, 2022, are as follows:


	Performance Unit Awards
	Shares	Weighted-Average Grant-Date Fair Value
Beginning nonvested grants	162,523	$	58.76
Granted	92,970	51.61
Vested	(58,889)	73.13
Forfeited	(2,197)	54.25
Remaining nonvested grants	194,407	$	51.04

We recognized compensation expense of $4.2 million and $3.9 million for the years ended December 31, 2022 and 2021 respectively, and related income tax benefit of $(1.3) million and $(0.2) million for the years ended December 31, 2022 and 2021 respectively. As of December 31, 2022, we had $6.4 million of unrecognized compensation cost related to the nonvested portion of outstanding awards, which is reflected as nonvested stock as a portion of additional paid in capital in our Statements of Common Shareholders' Equity. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $4.3 million and $4.2 million for the years ended December 31, 2022 and 2021 respectively.

Retirement/Retention Restricted Share Awards

In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. Awards granted before 2022 are subject to a five-year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Awards granted in 2022 and retirement/retention restricted share awards granted in the future no longer contain this performance measure,

instead these awards will vest after five full calendar years if the employee remains employed during that service period. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends.

A summary of nonvested shares as of and changes during the year ended December 31, 2022, are as follows:


	Shares	Weighted-Average Grant-Date Fair Value
Beginning nonvested grants	87,319	$	49.63
Granted	25,360	47.04
Vested	(13,394)	52.20
Forfeited	—	—
Remaining nonvested grants	99,285	$	48.62

Director's Deferred Compensation

Nonemployee directors may elect to defer up to 100 percent of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. The DSUs are marked-to-market on a quarterly basis with an adjustment to director’s compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number of years (not to exceed 10 years).

Following is a summary of the components of DSUs issued and compensation expense attributable to the DSUs (in millions, except DSU amounts):


	December 31,
	2022		2021
DSUs Issued	12,109		18,741

Compensation expense	0.7		1.1
Change in value of shares	0.1		1.3
Total compensation (benefit) expense	$	0.8	$	2.4

DSUs withdrawn	4,022		186,137
Value of DSUs withdrawn	$	0.2	$	12.1


(18)Common Stock

We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. Of these shares, 2,865,957 shares of common stock are reserved for the incentive plan awards. For further detail of grants under this plan see Note 17 - Stock-Based Compensation.

Repurchase of Common Stock

Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 16,120 and 16,880 during the years ended December 31, 2022 and 2021, respectively, and are reflected in reacquired capital. These shares were credited to reacquired capital based on their fair market value on the vesting date.

Issuance of Common Stock

In April 2021, we entered into an Equity Distribution Agreement with BofA Securities, Inc., CIBC World Markets Corp, Credit Suisse Securities (USA) LLC, and J.P. Morgan Securities LLC, collectively the sales agents, pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring on February 11, 2024. During the twelve months ended December 31, 2021, we issued 1,966,117 shares of our common stock under the ATM program at an average price of $63.81, for net proceeds of $124.0 million, which is net of sales commissions and other fees paid of approximately $1.3 million. We did not issue equity through the ATM program during 2022.

On November 17, 2021, we announced a registered public offering of 6,074,767 shares of our common stock at a public offering price of $53.50 per share, for an issuance amount of $325.0 million. In conjunction with this offering, we granted the underwriters an option to purchase up to 911,215 additional shares, which was subsequently exercised in full, for an additional issuance amount of $48.8 million. Of the total 6,985,982 shares of common stock offered, we initially sold 1,401,869 shares, $75.0 million in gross proceeds, directly to the underwriters in the offering, with cash proceeds received at closing. The remaining 5,584,113 shares were sold under forward sales agreements which provide for settlement on a settlement date or dates to be specified at our discretion, but which is expected to occur on or prior to February 28, 2023. The cumulative shares issued under the forward sales agreement is limited to one and one-half times the base number of shares within the agreement, or 8,376,170 shares.

The forward sales agreements were physically settled with common shares issued by us. On settlement dates, we issued shares of common stock to the forward purchaser at the then-applicable forward sale price and received issuance proceeds at that time. The forward sale price was initially $51.8950 per share, which was subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and was subject to decrease on certain dates specified in the forward sale agreement by amounts related to expected dividends on shares of common stock during the term of the forward sale agreement.

On June 24, 2022, we partially settled the forward sale agreement by physically delivering 2,004,483 shares of common stock in exchange for cash proceeds of $99.9 million, net of issuance costs. On September 21, 2022, we partially settled the forward sale agreement by physically delivering 1,618,932 shares of common stock in exchange for cash proceeds of approximately $80.0 million, net of issuance costs. On November 28, 2022, we partially settled the forward sale agreement by physically delivering 1,409,702 shares of common stock in exchange for cash proceeds of approximately $70.0 million, net of issuance costs. On December 21, 2022, we settled the remaining portion of the forward sale agreement by physically delivering 550,996 shares of common stock in exchange for cash proceeds of approximately $27.1 million, net of issuance costs. The proceeds were used to pay down borrowings under our revolving credit facility and for other general corporate purposes.

The forward sale agreement was classified as an equity transaction because it was indexed to our common stock, physical settlement was within our control, and the other requirements necessary for equity classification were met. As a result of the equity classification, no gain or loss was recognized within earnings due to subsequent changes in the fair value of the forward sales agreement.


(19)Commitments and Contingencies

Qualifying Facilities Liability

Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the Public Utility Regulatory Practices Act (PURPA). These contracts require us to purchase minimum amounts of energy at prices ranging from $64 to $136 per MWH through 2029. As of December 31, 2022, our estimated gross contractual obligation related to these contracts was approximately $386.1 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $327.8 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Operating expense and Operating revenues in our Statements of Income. The present value of the remaining liability is recorded in Accumulated miscellaneous operating provisions in our Balance Sheets. The following summarizes the change in the liability (in thousands):


	December 31,
	2022		2021
Beginning QF liability	$	64,943	$	81,379
Settlements(1)	(20,076)		(22,497)
Interest on long-term debt	4,861		6,061
Ending QF liability	$	49,728	$	64,943

______________________

(1) The primary components of the change in settlement amounts includes (i) a lower periodic adjustment of $5.4 million due to actual price escalation, which was less than previously modeled; (ii) higher costs of approximately $0.8 million, due to a $1.8 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $2.6 million reduction in costs in the prior period; and (iii) a prior year favorable adjustment of approximately $7.0 million decreasing the QF liability associated with a one-time clarification in contract term.

The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):


	Gross Obligation		Recoverable Amounts		Net
2023	$	80,750	$	61,280	$	19,470
2024	76,393		60,706		15,687
2025	60,360		52,950		7,410
2026	55,393		46,274		9,119
2027	56,665		46,668		9,997
Thereafter	56,534		59,895		(3,361)
Total(1)	$	386,095	$	327,773	$	58,322

_____________________

(1) This net unrecoverable amount represents the undiscounted difference between the total gross obligations and recoverable amounts. The ending QF liability in the table above represents the present value of this net unrecoverable amount.

Long Term Supply and Capacity Purchase Obligations

We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. Costs incurred under these contracts are included in Operating expenses in the Statements of Income and were approximately $328.0 million and $286.7 million for the years ended December 31, 2022 and 2021, respectively. As of December 31, 2022, our commitments under these

contracts were $413.4 million in 2023, $247.5 million in 2024, $235.8 million in 2025, $247.0 million in 2026, $230.3 million in 2027, and $1.5 billion thereafter. These commitments are not reflected in our Financial Statements.

Hydroelectric License Commitments

With the 2014 purchase of hydroelectric generating facilities and associated assets located in Montana, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $24.5 million between 2023 and 2040. These commitments are not reflected in our Financial Statements.


ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, our environmental reserve, which relates primarily to the remediation of former manufactured gas plant sites owned by us or for which we are responsible, is estimated to range between $21.6 million to $32.7 million. As of December 31, 2022, we had a reserve of approximately $26.4 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

The following summarizes the change in our environmental liability (in thousands):


	December 31,
	2022		2021
Liability at January 1,	$	26,866	$	28,895
Deductions	(2,033)		(2,799)
Charged to costs and expense	1,534		770
Liability at December 31,	$	26,367	$	26,866

Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our financial position or results of operations.

Manufactured Gas Plants - Approximately $20.5 million of our environmental reserve accrual is related to the following manufactured gas plants.

South Dakota - A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Agriculture and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2022, the reserve for remediation costs at this site was approximately $7.8 million, and we estimate that approximately $2.8 million of this amount will be incurred through 2025.

Nebraska - We own sites in North Platte, Kearney, and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

Montana - We own or have responsibility for sites in Butte, Missoula, and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana’s state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site.

In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and field work was completed in 2022. We submitted a Remedial Investigation Report (RI Report) summarizing the work completed to MDEQ and are awaiting its review and comments as to any additional field work. We expect the MDEQ review of the RI Report to be concluded in 2023, and any additional field work to commence following that.

MDEQ has indicated it expects to proceed in listing the Missoula site as a Montana superfund site. After researching historical ownership, we have identified another potentially responsible party with whom we have entered into an agreement allocating third-party costs to be incurred in addressing the site. The other party has assumed the lead role at the site and has expressed its intention to submit a voluntary remediation plan for the Missoula site to MDEQ. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of GHG including, most significantly, carbon dioxide (CO2) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and EPA actions at the federal level, state level activity, investor activism and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny. We have joint ownership interests in four coal-fired electric generating plants, all of which other companies operate. Despite efforts over the years, Congress has not passed any federal climate change legislation regarding GHG emissions from coal-fired plants. While, Section 111(d) of the Clean Air Act (CAA) confers authority on EPA and the states to regulate emissions, including GHGs, from existing stationary sources, no regulation has survived judicial review. In 2022 EPA opened a docket to collect public input to guide the EPA’s next effort to reduce GHG emissions from new and existing coal fired plants and natural gas operations. EPA indicated that it intends to use this non-rulemaking docket to gather perspectives from a broad group of stakeholders in advance of an expected proposed rulemaking. Ultimately, we cannot predict whether or how future GHG emission legislation, regulations, investor activism or litigation will impact our plants. As GHG regulations are implemented, it could result in additional compliance costs impacting our future results of operations and financial position, if such costs are not recovered through regulated rates. These could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions may not be available within a timeframe consistent with the implementation of any such requirements. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, wind, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and

transmission facilities. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any GHG regulations that, in our view, disproportionately impact our customers.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act (CAA) that could require the installation of emission control equipment at the generation plants in which we have joint ownership. Air emissions at our thermal generating plants are managed by the use of emissions and combustion controls and monitoring, and sulfur dioxide allowances. These measures are anticipated to be sufficient to permit the facilities to continue to meet current air emissions compliance requirements.

Regional Haze Rules - In January 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility - regional haze rules. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021.

The states of Montana, North Dakota and South Dakota have developed and submitted to the EPA, for its approval, their respective State Implementation Plans (SIP) for Regional Haze compliance. While these states, among others, did not meet the EPA’s July 31, 2021 submission deadline, they were all submitted in 2022. The Montana SIP as drafted and submitted to EPA does not call for additional controls for our interest in Colstrip Unit 4. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility. Similarly, the draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are finalized and approved by EPA, the potential remains that installation of additional emissions controls might be required at these facilities.

Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa, and Montana that are or may become subject to the various regulations discussed above that have been or may be issued or proposed.

Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

•We may not know all sites for which we are alleged or will be found to be responsible for remediation; and

•Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.


LEGAL PROCEEDINGS

Pacific Northwest Solar Litigation

Pacific Northwest Solar, LLC (PNWS) is a solar QF developer seeking to construct small solar facilities in Montana. We began negotiating with PNWS in early 2016 to purchase the output from 21 of its proposed facilities pursuant to our standard QF-1 Tariff, which is applicable to projects no larger than 3 MWs.

On June 16, 2016, however, the MPSC suspended the availability of the QF-1 Tariff standard rates for that category of solar projects, which included the projects proposed by PNWS. The MPSC exempted from the suspension any projects for which a QF had both submitted a signed power purchase agreement and had executed an interconnection agreement with us by June 16, 2016. Although we had signed four power purchase agreements with PNWS as of that date, we had not entered into interconnection agreements with PNWS for any of those projects. As a result, none of the PNWS projects in Montana qualified for the exemption.

In November 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and a judicial declaration that some or all of the 21 proposed power purchase agreements it had proposed to us were in effect despite the MPSC's Order. We removed the state lawsuit to the United States District Court for the District of Montana.

On August 31, 2021, the District Court ruled that the four agreements were valid and enforceable contracts and that we breached the agreements on June 16, 2016 by refusing to go forward with the projects in spite of the MPSC's Orders. On December 15, 2021, after a three-day trial, the jury determined that PNWS had sustained $0.5 million in damages and the judge subsequently entered judgment against us in that amount.

The appeal is fully briefed at the Ninth Circuit. Oral arguments were held on February 8, 2023.

Talen Montana Bankruptcy

On May 9, 2022 Talen Energy Supply, LLC (Talen Energy) along with 71 affiliated entities, filed bankruptcy in Houston, Texas, seeking reorganization under Chapter 11 (the Talen Bankruptcy). Talen Montana, LLC (Talen) was one of the affiliated entities that filed bankruptcy and is included as a part of the Talen Bankruptcy. Talen is one of the co-owners of Colstrip Units 1, 2 and 3, and the operator of Units 3 and 4. The Talen Bankruptcy filing, along with the automatic stay under §362 of the Bankruptcy Code, has affected pending legal proceedings in which both NorthWestern and Talen are involved, including the State of Montana-Riverbed Rents Litigation, the Colstrip Arbitration and Litigation, and the Colstrip Coal Dust Litigation, as described in the individual matters below. On December 15, 2022 the bankruptcy court confirmed Talen’s Chapter 11 Plan. Apart from the delays of legal proceedings due to the automatic stay, we have not noted any detrimental effect on the operation or Colstrip Units 3 and 4 caused by Talen’s bankruptcy.

State of Montana - Riverbed Rents

On April 1, 2016, the State of Montana (State) filed a complaint on remand (the State’s Complaint) with the Montana First Judicial District Court (State District Court), naming us, along with Talen as defendants. The State claimed it owns the riverbeds underlying 10 of our, and formerly Talen’s, hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan, and Morony facilities on the Missouri and Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.

The litigation has a long prior history. In 2012, the United States Supreme Court issued a decision holding that the Montana Supreme Court erred in not considering a segment-by-segment approach to determine navigability and relying on present day recreational use of the rivers. It also held that what it referred to as the Great Falls Reach “at least from the head of the first waterfall to the foot of the last” was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion. Following the 2012 remand, the case laid dormant for four years until the State’s Complaint was filed with the State District Court. On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court). On August 1, 2018, the Federal District Court granted our and Talen’s motions to dismiss the State’s Complaint as it pertains to the Great Falls Reach. A bench trial before the Federal District Court commenced January 4, 2022 and concluded on January 18, 2022, which addressed the issue of navigability. Damages were bifurcated by agreement and will be tried separately, should the Federal District Court find any segments navigable.

The Talen Bankruptcy filing in May 2022, and resulting automatic stay, resulted in a hold on this case, including a hold on any decision regarding navigability. In September 2022, the parties stipulated and the Bankruptcy Court issued its Order modifying the stay to permit the Federal District Court to issue its decision on the navigability phase of the case. We are awaiting the Federal District Court decision on navigability. The damages phase of the case remains stayed.

We dispute the State’s claims and intend to continue to vigorously defend the lawsuit. At this time, we cannot predict an outcome. If the Federal District Court determines the riverbeds are navigable under the remaining six facilities that were not dismissed and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $3.8 million commencing when we acquired the facilities in November 2014. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Colstrip Arbitration and Litigation

The six owners of Units 3 and 4 currently share the operating costs pursuant to the terms of an operating agreement among them, the Ownership and Operation Agreement (O&O Agreement). Costs of common facilities were historically shared among the owners of all four units. With the closure of Units 1 and 2, we have incurred additional operating costs with respect to our interest in Unit 4 and may experience a negative impact on our transmission revenue due to reduced amounts of energy transmitted across our transmission lines.

The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. Recovery of costs associated with the closure of the facility is subject to MPSC approval. Three of the joint owners of Units 3 and 4 are subject to regulation in Washington and in May 2019, the Washington state legislature enacted a statute mandating Washington electric utilities to “eliminate coal-fired resources from [their] allocation of electricity” on or before December 31, 2025, after which date they may no longer include their share of coal-fired resources in their regulated electric supply portfolio.

While we believe closure requires each owner’s consent, there are differences among the owners as to this issue under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), which seeks to resolve the primary issue of whether closure of Units 3 and 4 can be accomplished without each joint owner's consent and to clarify the obligations of the joint owners to continue to fund operations until all joint owners agree on closure.

While the pendency of the lawsuits involving Montana legislation that would have impacted the arbitration process and Talen's Bankruptcy delayed commencement of the Arbitration proceedings, and thus delayed resolution of the issues we raised when we commenced arbitration, since resolution of the lawsuits, the owners have initiated efforts to identify arbitrators pursuant to their stipulation entered in the Talen bankruptcy proceeding. Despite the litigation, we have worked and continue to work with the other joint owners to arrive at an agreed upon process for the Arbitration and a commercial resolution to the owners disagreements.

Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen, the operator of the Colstrip Units 1, 2, 3 and 4 (Colstrip), in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, as well as the other owners of Colstrip, and Westmoreland Rosebud Mining LLC, as defendants. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties. Talen’s bankruptcy and resulting automatic stay prevents the plaintiffs from pursuing their claims against Talen, but does not automatically prevent the plaintiffs from pursuing their claims against the other defendants. Based on a stipulation and Bankruptcy Court order, Talen's bankruptcy stay, as it concerns this matter, was lifted on February 13, 2023.

Since this lawsuit remains in its early stages, we are unable to predict outcomes or estimate a range of reasonably possible losses.

BNSF Demands for Indemnity and Remediation Costs

NorthWestern has received a demand for indemnity from BNSF Railway Company (BNSF) for past and future environmental investigation and remediation costs incurred by BNSF at one of the three operable units at the Anaconda Copper Mining (ACM) Smelter and Refinery Superfund Site, located near Great Falls, Montana. Smelter and refining operations at the site commenced in 1893 and continued until 1980.

According to U.S. EPA, the smelter and refining operations have contaminated soil, groundwater and surface water resources around the site with lead, arsenic and other metal wastes. ARCO (Atlantic Richfield Company) initiated reclamation and maintenance activities in the 1980s and 1990s. Between 2002 and 2008, the EPA conducted several site investigations. In March 2011, the EPA placed the ACM Smelter and Refinery Site on the Superfund program’s National Priority List. The Superfund Site is 427 acres and contains three operable units: Operable Unit 1 (consisting of five subsections including the Railroad Corridor and four other “areas of interest”), Operable Unit 2 (the former smelter and refinery site), and Operable Unit 3 (the Missouri River that flows along the south sides of Operable Units 1 and 2).

NorthWestern owns property in the Railroad Corridor sub-section of Operable Unit 1. BNSF claims it is entitled to indemnity and contribution from NorthWestern for the costs it has and will incur to investigate and remediate contamination in Operable Unit 1. BNSF reports it has incurred in excess of $4.4 million, pending final resolution of response and oversight costs incurred by government agencies (EPA and Montana DEQ), in investigative and other response costs associated with Operable Unit 1, and that in the future it will incur additional costs to implement the final remedy for Operable Unit 1. In the Record of Decision (ROD) for Operable Unit 1 issued on August 21, 2021, the EPA estimated the costs to implement the selected remedies for the Railroad Corridor will be approximately $4.1 million. In the ROD, the EPA also estimated the costs to implement the selected remedy (including institutional controls) for the four “areas of interest” in Operable Unit 1 would be approximately $1.8 million, with annual operating costs of ten thousand dollars. We are evaluating BNSF’s claim and are unable at this time to predict outcomes or estimate a range of reasonably possible losses.

Other Legal Proceedings

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In our opinion, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year		1,954,756		1,499,267	8,580,168		5,126,145
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income		(a) 436,295			(e) 452,130		15,835
3	Preceding Quarter/Year to Date Changes in Fair Value				(c) 57,286			57,286
4	Total (lines 2 and 3)		436,295		57,286	452,130		41,451	186,839,752	186,798,301
5	Balance of Account 219 at End of Preceding Quarter/Year		1,518,461		1,441,981	8,128,038		5,167,596
6	Balance of Account 219 at Beginning of Current Year		1,518,461		1,441,981	8,128,038		5,167,596
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income		(b) 982,991			(f) 452,130		530,861
8	Current Quarter/Year to Date Changes in Fair Value				(d) 7,207			7,207
9	Total (lines 7 and 8)		982,991		7,207	452,130		538,068	183,006,620	182,468,552
10	Balance of Account 219 at End of Current Quarter/Year		535,470		1,434,774	7,675,908		5,705,664

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedOtherComprehensiveIncomeLossMinimumPensionLiabilityAdjustmentReclassificationsToNetIncomeLoss

Postretirement medical liability adjustment.

(b) Concept: AccumulatedOtherComprehensiveIncomeLossMinimumPensionLiabilityAdjustmentReclassificationsToNetIncomeLoss

Postretirement medical liability adjustment.

Foreign currency translation adjustment.

(d) Concept: AccumulatedOtherComprehensiveIncomeLossOtherAdjustmentsToComprehensiveIncomeLossChangesInFairValue

Foreign currency translation adjustment.

(e) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsReclassificationsToNetIncomeLoss

Reclassification of net losses on derivative instruments.

(f) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsReclassificationsToNetIncomeLoss

Reclassification of net losses on derivative instruments.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	6,854,874,964	5,278,108,429	1,311,406,372	(d) 1,528,964			263,831,199
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	41,504,922				(e) 40,209,537	(f) 1,295,385
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified	4,244,173	4,244,173
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	6,900,624,059	5,282,352,602	1,311,406,372	1,528,964	40,209,537	1,295,385	263,831,199
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	4,327,380	4,297,515	29,865
11	ConstructionWorkInProgress Construction Work in Progress	300,649,215	256,812,052	26,659,721				17,177,442
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	686,328,435	(a) 686,328,435
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	7,891,929,089	6,229,790,604	1,338,095,958	1,528,964	40,209,537	1,295,385	281,008,641
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,786,711,964	2,147,837,398	531,948,773	1,087,519	33,172,848		72,665,426
15	UtilityPlantNet Net Utility Plant (13 less 14)	5,105,217,125	4,081,953,206	806,147,185	441,445	7,036,689	1,295,385	208,343,215
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,513,271,574	1,950,712,066	476,620,725	1,087,519	33,172,848		51,678,416
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights	48,504,666		48,504,666
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	52,020,462	(b) 24,210,070	6,823,382				20,987,010
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,613,796,702	1,974,922,136	531,948,773	1,087,519	33,172,848		72,665,426
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	172,915,262	(c) 172,915,262
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,786,711,964	2,147,837,398	531,948,773	1,087,519	33,172,848		72,665,426

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: UtilityPlantAcquisitionAdjustment

Acquisition Adjustments of $686,328,435 consists of $656,318,593 for Montana Operations and $30,009,842 for South Dakota Operations.

(b) Concept: AmortizationOfOtherUtilityPlantUtilityPlantInService

Amortization of Other South Dakota Electric Plant was $2,387 and $0 for 2022 and 2021, respectively.

Amortization of Other Montana Electric Plant was $24,207,683 and $22,153,646 for 2022 and 2021, respectively

Amortization of Plant Acquisition Adjustments of $172,915,262 consist of $164,212,408 for Montana Operations and $8,702,854 for South Dakota Operations.

(d) Concept: UtilityPlantInServiceClassified

This column represents regulated propane

(e) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

This column represents an electric default supply capacity and energy sales agreement classified as a capital lease.

(f) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

This column represents our right of use (operating lease) assets.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
1	Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2	Fabrication
3	Nuclear Materials
4	Allowance for Funds Used during Construction
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)
10	SUBTOTAL (Total 8 & 9)
11	Spent Nuclear Fuel (120.4)
12	Nuclear Fuel Under Capital Leases (120.6)
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
15	Estimated Net Salvage Value of Nuclear Materials in Line 9
16	Estimated Net Salvage Value of Nuclear Materials in Line 11
17	Est Net Salvage Value of Nuclear Materials in Chemical Processing
18	Nuclear Materials held for Sale (157)
19	Uranium
20	Plutonium
21	Other (Provide details in footnote)
22	TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization	(a) 19,995					19,995
3	(302) Franchise and Consents	(b) 19,288,558	959,050				20,247,608
4	(303) Miscellaneous Intangible Plant	7,274,966	5,250,785	248,808		25,232	12,251,711
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	26,583,519	6,209,835	248,808		25,232	32,519,314
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	812,637					812,637
9	(311) Structures and Improvements	55,183,001	375,725	35,863			55,522,863
10	(312) Boiler Plant Equipment	236,040,765	10,752,158	1,911,462		6,256	244,887,717
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	47,550,879	1,325,909	9,755			48,867,033
13	(315) Accessory Electric Equipment	15,319,421	444,082	106,139			15,657,364
14	(316) Misc. Power Plant Equipment	25,928,303	241,975	122,231			26,048,047
15	(317) Asset Retirement Costs for Steam Production	22,463,670					22,463,670
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	403,298,676	13,139,849	2,185,450		6,256	414,259,331
17	B. Nuclear Production Plant
18	(320) Land and Land Rights
19	(321) Structures and Improvements
20	(322) Reactor Plant Equipment
21	(323) Turbogenerator Units
22	(324) Accessory Electric Equipment
23	(325) Misc. Power Plant Equipment
24	(326) Asset Retirement Costs for Nuclear Production
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights
28	(331) Structures and Improvements	5,900,898	40,780				5,941,678
29	(332) Reservoirs, Dams, and Waterways	125,423,708	1,530,923	266,668			126,687,963
30	(333) Water Wheels, Turbines, and Generators	177,907,561	18,172,843	454,449			195,625,955
31	(334) Accessory Electric Equipment	151,379,698	29,192,061	3,786,313			176,785,446
32	(335) Misc. Power Plant Equipment	88,750,061	6,027,293	399,790			94,377,564
33	(336) Roads, Railroads, and Bridges	20,419,217	306,547				20,725,764
34	(337) Asset Retirement Costs for Hydraulic Production	2,493,836	458,810	5,550			2,947,096
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	572,274,979	55,729,257	4,912,770			623,091,466
36	D. Other Production Plant
37	(340) Land and Land Rights	3,901,868					3,901,868
38	(341) Structures and Improvements	86,227,692	22,947				86,250,639
39	(342) Fuel Holders, Products, and Accessories	26,525,671	8,707				26,534,378
40	(343) Prime Movers	147,196,133	85,611,878	1,957,034			230,850,977
41	(344) Generators	143,520,064					143,520,064
42	(345) Accessory Electric Equipment	27,116,751	4,079	40,824			27,080,006
43	(346) Misc. Power Plant Equipment	50,684,196	1,110,712				51,794,908
44	(347) Asset Retirement Costs for Other Production	5,038,356					5,038,356
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	490,210,731	86,758,323	1,997,858			574,971,196
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	1,465,784,386	155,627,429	9,096,078		6,256	1,612,321,993
47	3. Transmission Plant
48	(350) Land and Land Rights	41,959,408	347,229		305,787	63,313	41,854,653
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	50,881,687	7,965,346	16,159	1,260,743	1,241,202	61,332,819
50	(353) Station Equipment	411,210,108	24,478,079	1,373,583	2,399,114	3,692,781	440,406,499
51	(354) Towers and Fixtures	30,317,776	230,191	41,421	339,700		30,385,864
52	(355) Poles and Fixtures	484,534,670	45,008,102	3,305,354	1,221,670	8,348,679	519,110,409
53	(356) Overhead Conductors and Devices	206,913,694	6,750,145	529,018	1,448,089	1,645,387	212,937,523
54	(357) Underground Conduit	778,680					778,680
55	(358) Underground Conductors and Devices	6,631,465	9,510				6,640,975
56	(359) Roads and Trails	2,519,647	521,299		1,002,426		4,043,372
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	1,235,747,135	84,155,061	5,265,535	7,977,529	5,123,396	1,317,490,794
59	4. Distribution Plant
60	(360) Land and Land Rights	15,111,729	20,183	209,051		489,007	15,371,502
61	(361) Structures and Improvements	37,600,362	3,567,267	1		1,191,998	39,975,630
62	(362) Station Equipment	298,100,260	490,474	1,316,129		3,717,345	293,557,260
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	396,874,167	28,036,862	1,979,052		8,402,605	431,334,582
65	(365) Overhead Conductors and Devices	160,449,708	11,336,187	1,168,959		1,645,387	172,262,323
66	(366) Underground Conduit	166,295,854	12,941,537	258			179,237,133
67	(367) Underground Conductors and Devices	309,294,194	20,074,918	748,294		5,844	328,626,662
68	(368) Line Transformers	288,709,034	15,373,462	2,278,588		90,665	301,713,243
69	(369) Services	183,542,795	13,119,095	350,751			196,311,139
70	(370) Meters	78,725,104	17,783,111	5,514,819			90,993,396
71	(371) Installations on Customer Premises	94,490	683,485	31,888			746,087
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	85,946,211	7,155,927	1,909,902			91,192,236
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,020,743,908	130,542,142	15,507,692		5,542,835	2,141,321,193
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights
78	(381) Structures and Improvements
79	(382) Computer Hardware
80	(383) Computer Software
81	(384) Communication Equipment
82	(385) Miscellaneous Regional Transmission and Market Operation Plant
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85	6. General Plant
86	(389) Land and Land Rights	796,461					796,461
87	(390) Structures and Improvements	12,589,466	56,190	103,214			12,542,442
88	(391) Office Furniture and Equipment	1,597,950	84,728	466,240			1,216,438
89	(392) Transportation Equipment	79,526,197	3,768,222	474,406		1	82,820,012
90	(393) Stores Equipment	955,765	187,393				1,143,158
91	(394) Tools, Shop and Garage Equipment	12,367,082	653,745	437,213			12,583,614
92	(395) Laboratory Equipment	1,046,044		12,866			1,033,178
93	(396) Power Operated Equipment	6,774,037	701,087	83,252		1	7,391,873
94	(397) Communication Equipment	53,032,703	115,501	506,531	163,575		52,805,248
95	(398) Miscellaneous Equipment	2,110,622	36,911	24,822			2,122,711
96	SUBTOTAL (Enter Total of lines 86 thru 95)	170,796,327	5,603,777	2,108,544	163,575		174,455,135
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	170,796,327	5,603,777	2,108,544	163,575		174,455,135
100	TOTAL (Accounts 101 and 106)	4,919,655,275	382,138,244	32,226,657	8,141,104	400,463	5,278,108,429
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified	4,092,785	151,388				4,244,173
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	4,923,748,060	382,289,632	32,226,657	8,141,104	400,463	5,282,352,602

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: Organization

Montana operations


Line	Account	Beginning of Year	Additions	Retirements	Adjustments	Transfers	End of Year
No.	(a)	(b)	(c)	(d)	(e)	(f)	(g)
1	1. INTANGIBLE PLANT
2	(301) Organization	19,995	—	—	—	—	19,995
3	(302) Franchises and Consents	19,288,558	959,050	—	—	—	20,247,608
4	(303) Miscellaneous Intangible Plant	7,266,662	5,225,553	248,808	—	—	12,243,407
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and4)	26,575,215	6,184,603	248,808	—	—	32,511,010
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	446,126	—	—	—	—	446,126
9	(311) Structures and Improvements	28,016,189	263,464	29,133	—	—	28,250,520
10	(312) Boiler Plant Equipment	37,096,135	9,077,917	1,191,510	—	—	44,982,542
11	(313) Engines and Engine-Driven Generators	—	—	—	—	—	—
12	(314) Turbogenerator Units	21,259,205	1,004,205	8,324	—	—	22,255,086
13	(315) Accessory Electric Equipment	2,173,118	370,734	24,707	—	—	2,519,145
14	(316) Misc. Power Plant Equipment	22,952,383	17,517	22,226	—	—	22,947,674
15	(317) Asset Retirement Costs for Steam	19,799,959	—	—	—	—	19,799,959
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)	131,743,115	10,733,837	1,275,900	—	—	141,201,052
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	—	—	—	—	—	—
19	(321) Structures and Improvements	—	—	—	—	—	—
20	(322) Reactor Plant Equipment	—	—	—	—	—	—
21	(323) Turbogenerator Units	—	—	—	—	—	—
22	(324) Accessory Electric Equipment	—	—	—	—	—	—
23	(325) Misc. Power Plant Equipment	—	—	—	—	—	—
24	TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)	—	—	—	—	—	—
25	C. Hydraulic Production Plant
26	(330) Land and Land Rights	5,900,898	40,780	—	—	—	5,941,678
27	(331) Structures and Improvements	125,423,708	1,530,923	266,668	—	—	126,687,963
28	(332) Reservoirs, Dams, and Waterways	177,907,561	18,172,843	454,449	—	—	195,625,955


29	(333) Water Wheels, Turbines, and Generators	151,379,698	29,192,061	3,786,313	—	—	176,785,446
30	(334) Accessory Electric Equipment	88,750,061	6,027,293	399,790	—	—	94,377,564
31	(335) Misc. Power Plant Equipment	20,419,217	306,547	—	—	—	20,725,764
32	(336) Roads, Railroads, and Bridges	2,493,836	458,810	5,550	—	—	2,947,096
33	TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)	572,274,979	55,729,257	4,912,770	—	—	623,091,466
34	D. Other Production Plant
35	(340) Land and Land Rights	3,819,385	—	—	—	—	3,819,385
36	(341) Structures and Improvements	59,449,471	—	—	—	—	59,449,471
37	(342) Fuel Holders, Products, and Accessories	21,230,045	—	—	—	—	21,230,045
38	(343) Prime Movers	104,189,627	(695)	1,957,034	—	—	102,231,898
39	(344) Generators	55,657,436	—	—	—	—	55,657,436
40	(345) Accessory Electric Equipment	19,203,828	—	39,824	—	—	19,164,004
41	(346) Misc. Power Plant Equipment	28,134,319	956,704	—	—	—	29,091,023
42	(347) Asset Retirement Costs for Other Production	3,686,815	—	—	—		3,686,815
43	TOTAL Other Production Plant (Enter Total of lines 34 thru 40)	295,370,926	956,009	1,996,858	—	—	294,330,077
44	TOTAL Production Plant (Enter Total of lines 15, 23, 32, and 41)	999,389,020	67,419,103	8,185,528	—	—	1,058,622,595
45	3. TRANSMISSION PLANT
46	(350) Land and Land Rights	40,237,210	(359,629)	—	305,787	(63,313)	40,120,055
47	(352) Structures and Improvements	38,688,898	7,752,986	4,500	1,260,743	1,241,202	48,939,329
48	(353) Station Equipment	310,674,496	22,833,736	948,940	2,399,114	3,692,781	338,651,187
49	(354) Towers and Fixtures	30,317,776	(230,191)	41,421	339,700	—	30,385,864
50	(355) Poles and Fixtures	427,533,321	40,563,531	3,046,372	1,221,670	(8,348,679)	457,923,471
51	(356) Overhead Conductors and Devices	174,615,906	5,670,666	355,827	1,448,089	(1,645,387)	179,733,447
52	(357) Underground Conduit	137,878	—	—	—	—	137,878
53	(358) Underground Conductors and Devices	1,935,349	—	—	—	—	1,935,349
54	(359) Roads and Trails	2,519,647	521,299	—	1,002,426	—	4,043,372
55	TOTAL Transmission Plant (Enter Total of lines 44 thru 52)	1,026,660,481	76,752,398	4,397,060	7,977,529	(5,123,396)	1,101,869,952
56	4. DISTRIBUTION PLANT
57	(360) Land and Land Rights	14,264,151	(20,183)	1,018	—	489,007	14,731,957
58	(361) Structures and Improvements	36,244,428	3,439,175	1	—	(1,191,998)	38,491,604
59	(362) Station Equipment	253,396,250	(2,149,123)	1,090,301	—	(3,741,985)	246,414,841
60	(363) Storage Battery Equipment	—	—	—	—	—	—


61	(364) Poles, Towers, and Fixtures	341,701,090	23,602,844	1,249,449	—	8,348,679	372,403,164
62	(365) Overhead Conductors and Devices	139,507,502	9,444,506	126,478	—	1,645,387	150,470,917
63	(366) Underground Conduit	155,966,720	12,210,184	258	—	—	168,176,646
64	(367) Underground Conductors and Devices	249,832,503	15,703,271	346,059	—	—	265,189,715
65	(368) Line Transformers	246,552,092	13,627,506	1,777,937	—	—	258,401,661
66	(369) Services	162,264,238	11,835,498	207,051	—	—	173,892,685
67	(370) Meters	65,110,678	17,233,387	5,381,997	—	26,400	76,988,468
68	(371) Installations on Customer Premises	—	—	—	—	—	—
69	(372) Leased Property on Customer Premises	—	—	—	—	—	—
70	(373&388) Street Lighting and Signal Systems	76,698,030	6,840,044	1,806,922	—	—	81,731,152
71	(374) Asset Retirement Costs for Distribution Plant	—	—	—	—	—	—
72	TOTAL Distribution Plant (Enter Total of lines 55 thru 68)	1,741,537,682	111,767,109	11,987,471	—	5,575,490	1,846,892,810
73	5. GENERAL PLANT
74	(389) Land and Land Rights	689,633	—	—	—	—	689,633
75	(390) Structures and Improvements	10,804,083	(27,095)	78,500	—	—	10,698,488
76	(391) Office Furniture and Equipment	1,590,880	84,728	466,240	—	—	1,209,368
77	(392) Transportation Equipment	62,881,984	3,345,441	474,406	—	(1)	65,753,018
78	(393) Stores Equipment	955,765	187,393	—	—	—	1,143,158
79	(394) Tools, Shop and Garage Equipment	10,229,526	540,102	202,069	—	—	10,567,559
80	(395) Laboratory Equipment	1,046,044	—	12,866	—	—	1,033,178
81	(396) Power Operated Equipment	5,897,811	701,087	56,062	—	1	6,542,837
82	(397) Communication Equipment	49,859,138	67,346	389,747	163,575	—	49,700,312
83	(398) Miscellaneous Equipment	2,110,622	36,910	24,822	—	—	2,122,710
84	SUBTOTAL (Enter Total of lines 71 thru 80)	146,065,486	4,935,912	1,704,712	163,575	—	149,460,261
85	(399) Other Tangible Property	—	—	—	—	—	—
86	TOTAL General Plant (Enter Total of lines 81 and 82)	146,065,486	4,935,912	1,704,712	163,575	—	149,460,261
87	TOTAL (Accounts 101 and 106)	3,940,227,884	267,059,125	26,523,579	8,141,104	452,094	4,189,356,628
88	(102) Electric Plant Purchased (See Instr. 8)	—	—				—
89	(Less) (102) Electric Plant Sold (See Instr. 8)	—	—				—
90	(103) Experimental Plant Unclassified	4,092,785	151,388	—	—	—	4,244,173
91	TOTAL Electric Plant in Service(Enter Total of lines 84 thru 87)	3,944,320,669	267,210,513	26,523,579	8,141,104	452,094	4,193,600,801

(b) Concept: FranchisesAndConsents

South Dakota Operations


Line	Account	Beginning of Year	Additions	Retirement	Adjustments	Transfers	End of Year	Plant
No.	(a)	(b)	(c)	(d)	(e)	(f)	(g)	Acct
1	1. INTANGIBLE PLANT
2	(301) Organization	—	—	—	—	—	—	(301)
3	(302) Franchises and Consents	—	—	—	—	—	—	(302)
4	(303) Miscellaneous Intangible Plant	8,304	25,232	—	—	(25,232)	8,304	(303)
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and4)	8,304	25,232	—	—	(25,232)	8,304
6	2. PRODUCTION PLANT						—
7	A. Steam Production Plant						—
8	(310) Land and Land Rights	366,511	—	—	—	—	366,511	(310)
9	(311) Structures and Improvements	27,166,811	112,262	6,730	—	—	27,272,343	(311)
10	(312) Boiler Plant Equipment	198,944,630	1,674,241	719,952	—	6,256	199,905,175	(312)
11	(313) Engines and Engine-Driven Generators	—	—	—	—	—	—	(313)
12	(314) Turbogenerator Units	26,291,674	321,704	1,431	—	—	26,611,947	(314)
13	(315) Accessory Electric Equipment	13,146,303	73,348	81,432	—	—	13,138,219	(315)
14	(316) Misc. Power Plant Equipment	2,975,920	224,458	100,005	—	—	3,100,373	(316)
15	(317) Asset Retirement Costs for Steam	2,663,711	—	—	—	—	2,663,711
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)	271,555,560	2,406,013	909,550	—	6,256	273,058,279
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	—	—	—	—	—	—	(320)
19	(321) Structures and Improvements	—	—	—	—	—	—	(321)
20	(322) Reactor Plant Equipment	—	—	—	—	—	—	(322)
21	(323) Turbogenerator Units	—	—	—	—	—	—	(323)
22	(324) Accessory Electric Equipment	—	—	—	—	—	—	(324)
23	(325) Misc. Power Plant Equipment	—	—	—	—	—	—	(325)
24	TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)	—	—	—	—	—	—
25	C. Hydraulic Production Plant
26	(330) Land and Land Rights	—	—		—		—	(330)
27	(331) Structures and Improvements	—	—	—	—		—	(331)
28	(332) Reservoirs, Dams, and Waterways	—	—		—		—	(332)


29	(333) Water Wheels, Turbines, and Generators	—	—		—		—	(333)
30	(334) Accessory Electric Equipment	—	—		—		—	(334)
31	(335) Misc. Power Plant Equipment	—	—		—		—	(335)
32	(336) Roads, Railroads, and Bridges	—	—		—		—	(336)
33	TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)	—	—	—	—	—	—
34	D. Other Production Plant
35	(340) Land and Land Rights	82,483	—	—	—	—	82,483	(340)
36	(341) Structures and Improvements	26,778,221	22,947	—	—	—	26,801,168	(341)
37	(342) Fuel Holders, Products, and Accessories	5,295,626	8,707		—	—	5,304,333	(342)
38	(343) Prime Movers	43,006,506	85,612,573	—	—	—	128,619,079	(343)
39	(344) Generators	87,862,628	—	—	—	—	87,862,628	(344)
40	(345) Accessory Electric Equipment	7,912,923	4,079	1,000	—	—	7,916,002	(345)
41	(346) Misc. Power Plant Equipment	22,549,877	154,008	—	—	—	22,703,885	(346)
42	(347) Asset Retirement Costs for Other Production	1,351,541	—	—	—	—	1,351,541
43	TOTAL Other Production Plant (Enter Total of lines 34 thru 40)	194,839,805	85,802,314	1,000	—	—	280,641,119
44	TOTAL Production Plant (Enter Total of lines 15, 23, 32, and 41)	466,395,365	88,208,327	910,550	—	6,256	553,699,398
45	3. TRANSMISSION PLANT
46	(350) Land and Land Rights	1,722,199	12,400	—	—	—	1,734,599	(350)
47	(352) Structures and Improvements	12,192,789	212,360	11,659	—	—	12,393,490	(352)
48	(353) Station Equipment	100,535,612	1,644,343	424,643	—	—	101,755,312	(353)
49	(354) Towers and Fixtures	—	—	—	—	—	—	(354)
50	(355) Poles and Fixtures	57,001,349	4,444,569	258,982	—	—	61,186,936	(355)
51	(356) Overhead Conductors and Devices	32,297,788	1,079,479	173,191	—	—	33,204,076	(356)
52	(357) Underground Conduit	640,802	—	—	—	—	640,802	(357)
53	(358) Underground Conductors and Devices	4,696,115	9,510	—	—	—	4,705,625	(358)
54	(359) Roads and Trails	—	—	—	—		—	(359)
55	TOTAL Transmission Plant (Enter Total of lines 44 thru 52)	209,086,654	7,402,661	868,475	—	—	215,620,840
56	4. DISTRIBUTION PLANT
57	(360) Land and Land Rights	847,579	—	208,033	—	—	639,546	(360)
58	(361) Structures and Improvements	1,355,935	128,092	—	—	—	1,484,027	(361)
59	(362) Station Equipment	44,704,011	2,639,597	225,828	—	24,639	47,142,419	(362)
60	(363) Storage Battery Equipment	—		—	—	—	—	(363)


61	(364) Poles, Towers, and Fixtures	55,173,077	4,434,018	729,603	—	53,926	58,931,418	(364)
62	(365) Overhead Conductors and Devices	20,942,207	1,891,681	1,042,481	—		21,791,407	(365)
63	(366) Underground Conduit	10,329,133	731,353		—	—	11,060,486	(366)
64	(367) Underground Conductors and Devices	59,461,691	4,371,647	402,235	—	5,844	63,436,947	(367)
65	(368) Line Transformers	42,156,942	1,745,956	500,651	—	(90,665)	43,311,582	(368)
66	(369) Services	21,278,557	1,283,597	143,700	—	—	22,418,454	(369)
67	(370) Meters	13,614,426	549,724	132,822	—	(26,400)	14,004,928	(370)
68	(371) Installations on Customer Premises	94,489	683,485	31,888	—	—	746,086	(371)
69	(372) Leased Property on Customer Premises	—	—	—	—	—	—	(372)
70	(373&388) Street Lighting and Signal Systems	9,248,181	315,883	102,980	—	—	9,461,084	(373)
71	(374) Asset Retirement Costs for Distribution Plant	—	—	—	—	—	—	(374)
72	TOTAL Distribution Plant (Enter Total of lines 55 thru 68)	279,206,228	18,775,033	3,520,221	—	(32,656)	294,428,384
73	5. GENERAL PLANT
74	(389) Land and Land Rights	106,828	—	—	—	—	106,828	(389)
75	(390) Structures and Improvements	1,785,383	83,286	24,714	—	—	1,843,955	(390)
76	(391) Office Furniture and Equipment	7,070	—	—	—	—	7,070	(391)
77	(392) Transportation Equipment	16,644,213	422,782		—	—	17,066,995	(392)
78	(393) Stores Equipment	—	—	—	—	—	—	(393)
79	(394) Tools, Shop and Garage Equipment	2,137,556	113,644	235,144	—	—	2,016,056	(394)
80	(395) Laboratory Equipment	—	—	—	—	—	—	(395)
81	(396) Power Operated Equipment	876,226		27,190	—	—	849,036	(396)
82	(397) Communication Equipment	3,173,564	48,155	116,784	—	—	3,104,935	(397)
83	(398) Miscellaneous Equipment	—	—	—	—	—	—	(398)
84	SUBTOTAL (Enter Total of lines 71 thru 80)	24,730,840	667,867	403,832	—	—	24,994,875
85	(399) Other Tangible Property	—	—	—	—	—	—	(399)
86	TOTAL General Plant (Enter Total of lines 81 and 82)	24,730,840	667,867	403,832	—	—	24,994,875
87	TOTAL (Accounts 101 and 106)	979,427,391	115,079,120	5,703,078	—	(51,632)	1,088,751,801
88	(102) Electric Plant Purchased (See Instr. 8)	—	—				—	(102)
89	(Less) (102) Electric Plant Sold (See Instr. 8)	—	—		—		—	(102)


90	(103) Experimental Plant Unclassified	—	—				—	(103)
91	TOTAL Electric Plant in Service(Enter Total of lines 84 thru 87)	979,427,391	115,079,120	5,703,078	—	(51,632)	1,088,751,801

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	(a) Montana Operations:
3	Townsend Transmission Sub site	01/01/2011	12/01/2027	1,763,378
4	Missoula Miller Creek Sub site	01/01/2001	04/01/2024	625,904
5	Billings Metra Sub Site	07/01/2019	12/01/2028	595,346
6	Minor Projects (Less than $250,000 - 18 items)			1,312,887
21	Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL			4,297,515

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: ElectricPlantHeldForFutureUseDescription

This schedule represents Montana Operations only.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	MONTANA
2	Billings Capacity Planning	144,269,393
3	RIMROCK SUB REBUILD	26,970,015
4	Missoula City Rebuild	9,422,385
5	Morony Radial Gate Upgrade	8,366,344
6	2ND LAUREL CITY 100	5,353,169
7	LAUREL AUTO NETWORK	4,334,482
8	Cochrane U2 Turbine Upgrade	3,416,387
9	AMI Metering & Infrastructure	3,253,938
10	BASE Distribution Mgmt System	3,027,124
11	Bozeman Div Elec-Cap Blnkt Growth	2,133,238
12	Laurel Auto	2,111,220
13	Black Eagle U3 Turbine Upgrade	2,085,562
14	Holter U1 Turbine Upgrade	1,985,066
15	Yellowtail-Billings 230kV Pe	1,815,729
16	Holter U1 Generator Rewind	1,459,364
17	Bozeman Div Gas-Cap Blnkt Growth	1,302,353
18	Billings Div Elec-Cap Blnkt Growth	1,170,317
19	LAUREL AUTO TPIF	1,093,444
20	Hamilton Heights	1,056,230
21	Ashgrove XFMR Upgrade	1,015,048
22	Minor Projects (Less than $1,000,000 - 285 items)	22,976,284
23	SOUTH DAKOTA
24	Minor Projects (Less than $1,000,000 - 183 items)	8,194,960
43	Total	256,812,052

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	(a) 1,857,591,459	1,857,591,459
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	134,285,355	134,285,355
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	134,285,355	134,285,355
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	31,977,847	31,977,847
13	CostOfRemovalOfPlant Cost of Removal	19,389,952	19,389,952
14	SalvageValueOfRetiredPlant Salvage (Credit)	2,428,886	2,428,886
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	48,938,913	48,938,913
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	65,822	65,822
17.2	Transfers	7,839,987	7,839,987
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	1,950,712,066	1,950,712,066
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	148,747,306	148,747,306
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	145,873,338	145,873,338
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	154,947,244	154,947,244
25	AccumulatedDepreciationTransmission Transmission	486,822,717	486,822,717
26	AccumulatedDepreciationDistribution Distribution	912,728,089	912,728,089
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	101,593,372	101,593,372
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	1,950,712,066	1,950,712,066

FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForDepreciationOfElectricUtilityPlant

Montana Operations


Section A. Balances and Changes During Year 2022 MONTANA DATA ONLY
Line No.	Item	Total (c+d+e)	Electric Plant in Service
	(a)	(b)	(c)
1	Balance Beginning of Year	1,519,958,162	1,519,958,162
2	Depreciation Provisions for Year, Charged to
3	(403) Depreciation Expense	104,208,637	104,208,637
4	(403.1) Depreciation Expense for Asset Retirement Costs
5	(413) Exp. of Elec. Plt. Leas. to Others
6	Transportation Expenses-Clearing
7	Other Clearing Accounts
8	Other Accounts (Specify, details in footnote):
9
10	TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	104,208,637	104,208,637
11	Net Charges for Plant Retired:
12	Book Cost of Plant Retired	26,274,772	26,274,772
13	Cost of Removal	17,764,165	17,764,165
14	Salvage (Credit)	1,912,063	1,912,063
15	TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	42,126,874	42,126,874
16	Other Debit or Cr. Items (Describe, details in footnote):	(61,475)	(61,475)
17	Transfers	7,839,987	7,839,987
18	Book Cost or Asset Retirement Costs Retired
19	Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	1,589,818,437	1,589,818,437
Section B. Balances at End of Year According to Functional Classification
20	Steam Production	31,061,530	31,061,530
21	Nuclear Production	—
22	Hydraulic Production-Conventional	145,873,338	145,873,338
23	Hydraulic Production-Pumped Storage	—	—
24	Other Production	99,678,333	99,678,333
25	Transmission	407,945,406	407,945,406
26	Distribution	813,998,961	813,998,961
27	General	91,260,869	91,260,869
28	TOTAL (Enter Total of lines 20 thru 27)	1,589,818,437	1,589,818,437

South Dakota Operations


Section A. Balances and Changes During Year 2022 SOUTH DAKOTA DATA ONLY
Line No.	Item	Total (c+d+e)	Electric Plant in Service
	(a)	(b)	(c)
1	Balance Beginning of Year	337,633,297	337,633,297
2	Depreciation Provisions for Year, Charged to
3	(403) Depreciation Expense	30,076,718	30,076,718
4	(403.1) Depreciation Expense for Asset Retirement Costs
5	(413) Exp. of Elec. Plt. Leas. to Others
6	Transportation Expenses-Clearing
7	Other Clearing Accounts
8	Other Accounts (Specify, details in footnote):
9
10	TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	30,076,718	30,076,718
11	Net Charges for Plant Retired:
12	Book Cost of Plant Retired	5,703,075	5,703,075
13	Cost of Removal	1,625,787	1,625,787
14	Salvage (Credit)	516,823	516,823
15	TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	6,812,039	6,812,039
16	Other Debit or Cr. Items (Describe, details in footnote):	-4,347	-4,347
17
18	Book Cost or Asset Retirement Costs Retired	—	—
19	Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	360,897,976	360,893,629
Section B. Balances at End of Year According to Functional Classification
20	Steam Production	117,685,776	117,685,776
21	Nuclear Production	—	—
22	Hydraulic Production-Conventional	—	—
23	Hydraulic Production-Pumped Storage	—	—
24	Other Production	55,268,911	55,268,911
25	Transmission	78,877,311	78,877,311
26	Distribution	98,729,128	98,729,128
27	General	10,332,503	10,332,503
28	TOTAL (Enter Total of lines 20 thru 27)	360,893,629	360,893,629


Section A. Balances and Changes During Year 2021 SOUTH DAKOTA DATA ONLY
Line No.	Item	Total (c+d+e)	Electric Plant in Service
	(a)	(b)	(c)
1	Balance Beginning of Year	323,696,821	323,696,821
2	Depreciation Provisions for Year, Charged to
3	(403) Depreciation Expense	25,161,804	25,161,804
4	(403.1) Depreciation Expense for Asset Retirement Costs
5	(413) Exp. of Elec. Plt. Leas. to Others
6	Transportation Expenses-Clearing
7	Other Clearing Accounts
8	Other Accounts (Specify, details in footnote):
9
10	TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	25,161,804	25,161,804
11	Net Charges for Plant Retired:
12	Book Cost of Plant Retired	9,104,054	9,104,054
13	Cost of Removal	2,801,112	2,801,112
14	Salvage (Credit)	679,838	679,838
15	TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	11,225,328	11,225,328
16	Other Debit or Cr. Items (Describe, details in footnote):	—	—
17
18	Book Cost or Asset Retirement Costs Retired	—	—
19	Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	337,633,297	337,633,297
Section B. Balances at End of Year According to Functional Classification
20	Steam Production	115,184,173	115,184,173
21	Nuclear Production	—	—
22	Hydraulic Production-Conventional	—	—
23	Hydraulic Production-Pumped Storage	—	—
24	Other Production	47,743,025	47,743,025
25	Transmission	73,951,723	73,951,723
26	Distribution	91,696,770	91,696,770
27	General	9,057,606	9,057,606
28	TOTAL (Enter Total of lines 20 thru 27)	337,633,297	337,633,297

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1	NorthWestern Services, LLC
2	NorthWestern Services, LLC - Capital Stock
3	NorthWestern Services, LLC - Paid in Capital			1,803,694			1,803,694
4	NorthWestern Services, LLC - Equity in Undistributed Earnings			260,348	27,103		287,451
5	Risk Partners Assurance, Ltd.
6	Risk Partners Assurance, Ltd. - Capital Stock			1,520,000			1,520,000
7	Risk Partners Assurance, Ltd. - Equity in Undistributed Earnings			329,860	58,850		388,710
8	Canadian Montana Pipeline Corporation	02/15/2002
9	Canadian Montana Pipeline Corporation - Translation Adjustment			1,691,139			1,683,932
10	Canadian Montana Pipeline Corporation - Paid in Capital			1,388,429			1,388,429
11	Canadian Montana Pipeline Corporation - Equity in Undistributed Earnings			1,787,411	124,064		1,911,475
12	Havre Pipeline Company	12/01/2013
13	Havre Pipeline Company - Paid in Capital			13,346,105			13,376,259
14	Havre Pipeline Company - Equity in Undistributed Earnings			1,216,045	760,821		1,976,866
15	NorthWestern Energy Solutions	06/01/2018
16	NorthWestern Energy Solutions - Capital Stock			4,182,095			5,793,954
17	NorthWestern Energy Solutions - Equity in Undistributed Earnings			55,781	99		55,682
42	Total Cost of Account 123.1 $		Total	24,377,535	668,404		25,343,937

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	7,509,623	7,724,941	Electric & Gas
2	Fuel Stock Expenses Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	51,295,115	67,595,939	Electric, Gas, & Common
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	517,603	733,334	Electric & Gas
8	Transmission Plant (Estimated)	458,202	767,707	Electric, Gas, & Common
9	Distribution Plant (Estimated)	1,267,805	2,057,268	Electric, Gas, & Common
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	53,538,725	71,154,248
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies	61,048,348	(a)(b) 78,879,189

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: MaterialsAndOperatingSupplies

Montana Operations


Line No.	Account (a)	Gas (b)	Electric Transmission (c )	Other Electric (d)	Total (e)
1	Fuel Stock (Account 151)	995,160		1,288,342	2,283,502
2	Fuel Stock Expense Undistributed (Account 152)				—
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	8,520,911	8,016,668	34,409,326	50,946,905
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	1,066	—	324,798	325,864
8	Transmission Plant (Estimated)	128,524	369,330	—	497,854
9	Distribution Plant (Estimated)	262,970	—	1,260,448	1,523,418
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other
12	TOTAL Account 154 (Enter Total of lines 5 thru 10)	8,913,471	8,385,998	35,994,572	53,294,041
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157)
16	Store Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies (Per Balance Sheet)	9,908,631	8,385,998	37,282,914	55,577,543

(b) Concept: MaterialsAndOperatingSupplies

Montana Operations


Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c )	Estimate of Portion Attributable to Construction	Balance End of Year w/ Assigned to Construction (c )	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	1,858,899	2,283,502		2,283,502	Electric & Gas
2	Fuel Stock Expense Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	—	—	50,946,905	50,946,905	Electric, Gas, & Common
6	Assigned to - Operatons and Maintenance		—
7	Production Plant (Estimated)	6,906,484	7,399,061	(7,072,199)	325,864	Electric & Gas
8	Transmission Plant (Estimated)	7,821,658	11,304,264	(10,806,409)	497,854	Electric, Gas, & Common
9	Distribution Plant (Estimated)	23,760,481	34,590,716	(33,067,297)	1,523,418	Electric, Gas, & Common
10	Regional Transmission and Market Operation Plant (Estimated)		0
11	Assigned to - Other	—	—		—
12	TOTAL Account 154 (Enter Total of lines 5 thru 10)	38,488,623	53,294,041	1,000	53,294,041
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157)
16	Store Expense Undistributed (Account 163)	—	—
17
18
19
20	TOTAL Materials and Supplies (Per Balance Sheet)	40,347,522	55,577,543	1,000	55,577,543

South Dakota Operations


Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c )	Estimate of Portion Attributable to Construction	Balance End of Year w/ Assigned to Construction (c )	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	5,650,724	5,441,439		5,441,439	Electric & Gas
2	Fuel Stock Expense Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	—	—	16,649,035	16,649,035	Electric & Gas
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	5,317,724	6,008,636	(5,601,166)	407,470	Electric & Gas
8	Transmission Plant (Estimated)	3,109,821	3,979,312	(3,709,458)	269,854	Electric & Gas
9	Distribution Plant (Estimated)	6,622,557	7,872,259	(7,338,411)	533,848	Electric & Gas
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other	—	—		—	Common
12	TOTAL Account 154 (Enter Total of lines 5 thru 10)	15,050,102	17,860,207	—	17,860,207
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)					Electric & Gas
15	Nuclear Materials Held for Sale (Account 157)
16	Store Expense Undistributed (Account 163)					Electric & Gas
17
18
19
20	TOTAL Materials and Supplies (Per Balance Sheet)	20,700,826	23,301,646	—	23,301,646

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	4,106		4,106		4,106		4,106		49,450		65,874
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year	4,106		4,106		4,106		4,106		42,992		59,416
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
20	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (f)
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	FAC Studies	59,076	253	59,019	253
3	SIS Studies	98,971	253	102,572	253
4	Line Interconnection Studies	40,115	253	76,314	253
20	Total	198,162		237,905
21	Generation Studies
22	FAC Studies	191,204	253	1,328,614	253
23	SIS Studies	175,910	253	906,285	253
24	FEA Studies	141,452	253	425,549	253
25	Optional Studies	9,297	253	110,322	253
39	Total	517,863		2,770,770
40	Grand Total	716,025		3,008,675

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Flow-through Income Taxes (Montana)	405,926,858	38,459,263	Various		444,386,121
2	Excess Deferred Income Taxes (Montana)	53,729,445		410.1	6,280,608	(a) 47,448,837
3	Basin Creek Capital Lease (Montana)	5,724,239		243	864,276	4,859,963
4	BPA Residential Exchange Program (Montana) - Docket 2018.8.49 Order 7630; Annual Amortization	1,264,780	6,423,520	254	6,494,928	1,193,372
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	1,668,316	11,432,710	(2)407	1,668,316	11,432,710
6	FAS 106 (Montana) - Docket 93.6.24 and Docket 2009.9.129	4,476,121	6,475,046	(2)926	292,434	10,658,733
7	FAS 112 (Montana) - Docket 93.6.24 and Docket 2009.9.129	5,393,028	486,247	(2)926		5,879,275
8	Compensated Absences (Montana) - Docket 97.11.219	11,778,804	599,294	242	995,996	11,382,102
9	Pension Plan (Montana)	93,031,712			12,146,625	80,885,087
10	Montana Consumer Counsel Tax (Montana) - Docket 2018.10.67 - Order 7637	561,618	77,789	Various		639,407
11	Montana Public Service Commission (Montana) - Docket 2017.9.78 - Order 7568	4,283,963	447,555		1,160,624	3,570,894
12	Natural Gas Transmission Verification Program (Montana) - Docket D2016.11.88	1,151,087		(2)407	566,840	584,247
13	Study of the Costs & Benefits of Customer Generators (Montana)	65,994			65,994
14	Asset Retirement Obligation (Montana)	12,616,717	2,804,786			15,421,503
15	Flow-through Income Taxes (South Dakota)	58,736,849	5,915,353			64,652,202
16	Excess Deferred Income Taxes (South Dakota)	7,083,285			167,880	6,915,405
17	Pension Plan (South Dakota)	5,304,230	1,775,472			(b) 7,079,702
18	Manufactured Gas Plants (South Dakota) - Docket NG 11-003	11,261,735	28,618		327,624	10,962,729
19	Field Inventory (South Dakota) - Docket EL 14-106	352,107			89,916	262,191
20	Asset Retirement Obligation (South Dakota)	737,896	132,000			869,896
44	TOTAL	685,148,784	75,057,653		31,122,061	729,084,376

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssets


Line No.	Description (a)	(b)	(c)	(d)

	MONTANA:
		12/31/2021
		Protected	Unprotected
	TCJA Excess ADIT Account Reduced	190	190	Subtotal
	Reg Asset Acccount Impacted	182.3	182.3	182.3
1	Electric:
2	Regulatory Assets / Liabilities		(8,341)	(8,341)
3	Unbilled Revenue		687,232	687,232
4	Compensation Accruals		751,386	751,386
5	Reserves & Accruals		179,940	179,940
6	Intangible amortization		—	—
7	Pension / Postretirement Benefits		4,927,736	4,927,736
8	Environmental Liability		264,469	264,469
9	Interest Rate Hedge		—	—
10	Customer Advances		2,329,891	2,329,891
11	Excess Tax Depreciation / Other Property			—
12	Net Operating Loss	26,940,081	—	26,940,081
13	Total Electric	26,940,081	9,132,313	36,072,394
14	Gas:
15	Regulatory Assets / Liabilities		(25,641)	(25,641)
16	Unbilled Revenue		534,514	534,514
17	Compensation Accruals		584,411	584,411
18	Reserves & Accruals		116,195	116,195
19	Intangible amortization		—	—
20	Pension / Postretirement Benefits		3,834,145	3,834,145
21	Environmental Liability		205,698	205,698
22	Interest Rate Hedge		—	—
23	Customer Advances		1,264,062	1,264,062
24	Excess Tax Depreciation / Other Property			—
25	Net Operating Loss	(3,503,486)	—	(3,503,486)
26	Total Gas	(3,503,486)	6,513,384	3,009,898
27	Other (Specify)	—	498,848	498,848
28	Subtotal	23,436,595	16,144,545	39,581,140
29	Gross-up	8,377,427	5,770,878	14,148,305
30	Total	31,814,022	21,915,423	53,729,445
31
32	Other (Specify)
33	QF Obligations	—	—	—
34	NOL Carryforward	—	—	—
35	AMT Credit Carryforward	—	—	—
36	Production Tax Credit	—	—	—
37	Regulatory Assets / Liabilities	—	—	—
38	Other, net	—	498,848	498,848
39	Total	—	498,848	498,848
40
41
42		12/31/2022
43		Protected	Unprotected


44	TCJA Excess ADIT Account Reduced	190	190	Subtotal
45	Reg Asset Acccount Impacted	182.3	182.3	182.3
46	Electric:
47	Regulatory Assets / Liabilities		3,671	3,671
48	Unbilled Revenue		412,339	412,339
49	Compensation Accruals		450,831	450,831
50	Reserves & Accruals		107,964	107,964
51	Intangible amortization		—	—
52	Pension / Postretirement Benefits		2,956,642	2,956,642
53	Environmental Liability		158,682	158,682
54	Interest Rate Hedge		—	—
55	Customer Advances		1,397,935	1,397,935
56	Excess Tax Depreciation / Other Property			—
57	Net Operating Loss	26,018,461	—	26,018,461
58	Total Electric	26,018,461	5,488,064	31,506,525
59	Gas:
60	Regulatory Assets / Liabilities		(25,641)	(25,641)
61	Unbilled Revenue		534,514	534,514
62	Compensation Accruals		584,411	584,411
63	Reserves & Accruals		116,195	116,195
64	Intangible amortization		—	—
65	Pension / Postretirement Benefits		3,834,145	3,834,145
66	Environmental Liability		205,698	205,698
67	Interest Rate Hedge		—	—
68	Customer Advances		1,264,062	1,264,062
69	Excess Tax Depreciation / Other Property			—
70	Net Operating Loss	(3,384,786)	—	(3,384,786)
71	Total Gas	(3,384,786)	6,513,384	3,128,598
72	Other (Specify)	—	319,251	319,251
73	Subtotal	22,633,675	12,320,699	34,954,374
74	Gross-up	8,090,423	4,404,043	12,494,466
75	Total	30,724,098	16,724,742	47,448,840
76
77	Other (Specify)
78	QF Obligations	—	—	—
79	NOL Carryforward	—	—	—
80	AMT Credit Carryforward	—	—	—
81	Production Tax Credit	—	—	—
82	Regulatory Assets / Liabilities	—	—	—
83	Other, net	—	319,251	319,251
84	Total	—	319,251	319,251
85
86
87	SOUTH DAKOTA:
88		12/31/2021
89		Protected	Unprotected
90	TCJA Excess ADIT Account Reduced	190	190	Subtotal
91	Reg Asset Acccount Impacted	182.3	182.3	182.3
92	Electric:
93	Regulatory Assets / Liabilities		—	—
94	Unbilled Revenue		—	—
95	Compensation Accruals		—	—
96	Reserves & Accruals		—	—
97	Intangible amortization		—	—
98	Pension / Postretirement Benefits		—	—


99	Environmental Liability		—	—
100	Interest Rate Hedge		—	—
101	Customer Advances		—	—
102	Excess Tax Depreciation / Other Property			—
103	Net Operating Loss	4,001,825	—	4,001,825
104	Total Electric	4,001,825	—	4,001,825
105	Gas:
106	Regulatory Assets / Liabilities		—	—
107	Unbilled Revenue		237,268	237,268
108	Compensation Accruals		895,742	895,742
109	Reserves & Accruals		66,862	66,862
110	Intangible amortization		—	—
111	Pension / Postretirement Benefits		(67,853)	(67,853)
112	Environmental Liability		491,773	491,773
113	Interest Rate Hedge		—	—
114	Customer Advances		—	—
115	Excess Tax Depreciation / Other Property			—
116	Net Operating Loss	(159,752)	—	(159,752)
117	Total Gas	(159,752)	1,623,792	1,464,040
118	Other (Specify)	—	129,930	129,930
119	Subtotal	3,842,073	1,753,722	5,595,795
120	Gross-up	1,021,311	466,179	1,487,490
121	Total	4,863,384	2,219,901	7,083,285
122
123	Other (Specify)
124	QF Obligations	—	—	—
125	NOL Carryforward	—	—	—
126	AMT Credit Carryforward	—	—	—
127	Production Tax Credit	—	—	—
128	Regulatory Assets / Liabilities	—	—	—
129	Other, net	—	129,930	129,930
130	Total	—	129,930	129,930
131
132
133		12/31/2022
134		Protected	Unprotected
135	TCJA Excess ADIT Account Reduced	190	190	Subtotal
136	Reg Asset Acccount Impacted	182.3	182.3	182.3
137	Electric:
138	Regulatory Assets / Liabilities		—	—
139	Unbilled Revenue		—	—
140	Compensation Accruals		—	—
141	Reserves & Accruals		—	—
142	Intangible amortization		—	—
143	Pension / Postretirement Benefits		—	—
144	Environmental Liability		—	—
145	Interest Rate Hedge		—	—
146	Customer Advances		—	—
147	Excess Tax Depreciation / Other Property			—
148	Net Operating Loss	3,863,687	—	3,863,687
149	Total Electric	3,863,687	—	3,863,687
150	Gas:
151	Regulatory Assets / Liabilities		—	—
152	Unbilled Revenue		237,268	237,268
153	Compensation Accruals		895,742	895,742


154	Reserves & Accruals		66,861	66,861
155	Intangible amortization		—	—
156	Pension / Postretirement Benefits		(67,853)	(67,853)
157	Environmental Liability		491,773	491,773
158	Interest Rate Hedge		—	—
159	Customer Advances		—	—
160	Excess Tax Depreciation / Other Property			—
161	Net Operating Loss	(154,239)	—	(154,239)
162	Total Gas	(154,239)	1,623,791	1,469,552
163	Other (Specify)	—	129,930	129,930
164	Subtotal	3,709,448	1,753,721	5,463,169
165	Gross-up	986,056	466,179	1,452,235
166	Total	4,695,504	2,219,900	6,915,404
167
168	Other (Specify)
169	QF Obligations	—	—	—
170	NOL Carryforward	—	—	—
171	AMT Credit Carryforward	—	—	—
172	Production Tax Credit	—	—	—
173	Regulatory Assets / Liabilities	—	—	—
174	Other, net	—	129,930	129,930
175	Total	—	129,930	129,930

(b) Concept: OtherRegulatoryAssets

Refer to footnote at column (f) line 2 for details.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Montana Operations:
2	Energy Stored in Out of State Utilities (Montana)	2,143	81,768	555	80,956	2,955
3	500 kV Operations - Partner's Share (Montana)	149,231		131		149,231
4	PPLM Share of WET Tax (Montana)	975	40,489	131	39,408	2,056
5	Transmission Line Rights (Montana)	227,282		116	90,909	136,373
6	South Dakota Operations:
7	Deferred Fuel for Electric Generation (South Dakota)	224,272	7,810,559	547	7,168,361	866,470
8	Pension Requirement (South Dakota)	8,297,060	1,319,464	253	2,421,687	7,194,837
9	Corporate Operations
10	Unamortized Debt Expense (Corporate)		3,411,389	930.2	1,921,692	1,489,697
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	8,602,501				9,543,157

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	Regulatory Asset/Liability	(a) 61,733	344,029
3	Unbilled Revenue	7,253,941	6,487,879
4	Compensation Accruals	6,881,461	6,721,853
5	Reserves and Accruals	5,251,728	4,211,397
6	Pension/Postretirement Benefits	15,636,841	13,991,466
7	Other	(b) 23,120,514	26,910,196
8	TOTAL Electric (Enter Total of lines 2 thru 7)	58,206,218	58,666,820
9	Gas
10	Regulatory Asset/Liability	115,910	243,159
11	Unbilled Revenue	3,449,825	2,951,879
12	Compensation Accruals	3,730,902	3,584,320
13	Reserves and Accruals	640,552	550,599
14	Pension/Postretirement Benefits	5,797,891	5,299,035
15	Other	(c) 7,012,661	7,591,054
16	TOTAL Gas (Enter Total of lines 10 thru 15)	20,747,741	20,220,046
17.1	Other (Specify)	(d) 81,960,145	85,056,758
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	160,914,104	163,943,624

Notes

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes


Accumulated Deferred Income Taxes (Account 190)		MONTANA OPERATIONS		SOUTH DAKOTA OPERATIONS
Line No.	Description and Location (a)	Balance at Beg of Year	Balance at End of Year	Balance at Beg of Year	Balance at End of Year
		(b)	(c)	(b)	(c)

	Electric:
1	Regulatory Assets/Liabilities	61,733	344,029	—	—
2	Unbilled Revenue	5,199,060	5,028,140	2,054,881	1,459,739
3	Compensation Accruals	3,434,770	3,527,251	3,446,691	3,194,602
4	Reserves & Accruals	4,865,834	3,765,150	385,894	446,247
5	Pension / Postretirement Benefits	16,564,125	14,498,131	(927,284)	(506,665)
6	Environmental Liability	1,519,396	1,678,401	2,119,317	2,168,426
7	Interest Rate Hedge	3,690,192	3,528,578		(90,541)
8	Customer Advances	16,323,844	19,625,332
9	NOL Carryforward	—	—	—	—
10	Total Electric	51,658,954	51,995,012	7,079,499	6,671,808
11	Gas:
12	Regulatory Liabilities	9,204	118,933	106,706	124,226
13	Unbilled Revenue	2,021,857	1,954,876	1,427,968	997,003
14	Compensation Accruals	1,335,743	1,371,709	2,395,159	2,212,611
15	Reserves & Accruals	372,389	238,732	268,163	311,867
16	Pension / Postretirement Benefits	6,442,275	5,638,832	(644,384)	(339,797)
17	Environmental Liability	592,392	654,227	1,472,745	1,508,307
18	Interest Rate Hedge	—	—	—	(65,564)
19	Customer Advances	4,947,524	5,494,084	—	—
20	NOL Carryforward	—	—	—	—
21	Total Gas	15,721,384	15,471,393	5,026,357	4,748,653
22	Other (Specify)	540,792	34,231,600	963,409	53,332,859
23	Total (Acct 190) (Total of lines 10, 20, and 21)	67,921,130	101,698,005	13,069,265	64,753,320

	Account 190 Other (Specify)
	QF Obligations	—	—	—	—
	NOL Carryforward	—	—	—	—
	Production Tax Credit	—	28,869,105	—	51,227,891
	Other, net	540,792	5,362,495	963,409	2,104,968
	Total	540,792	34,231,600	963,409	53,332,859

(b) Concept: AccumulatedDeferredIncomeTaxes


Electric Other:	Balance at Beg of Year	Balance at End of Year
(a)	(b)	(c)
Environmental Liability	3,638,713	3,846,827
Interest Rate Hedge	3,157,957	3,438,037
Customer Advances	16,323,844	19,625,332
	23,120,514	26,910,196


Gas Other:	Balance at Beg of Year	Balance at End of Year
(a)	(b)	(c)
Environmental Liability	2,065,137	2,162,534
Interest Rate Hedge	—	(65,564)
Customer Advances	4,947,524	5,494,084
	7,012,661	7,591,054

(d) Concept: AccumulatedDeferredIncomeTaxes


Description and Location	Balance at Beg of Year	Balance at End of Year
Line 17 Detail
Production Tax Credit	75,091,906	80,096,996
Other, net	6,868,239	4,959,762
Total	81,960,145	85,056,758

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2	Common Stock (NASDQ)	200,000,000	0.01		63,278,307	632,782	3,534,177	98,392,040
9	Total	200,000,000			63,278,307	632,782
10	Preferred Stock (Account 204)
11	Preferred Stock - None issued	50,000,000	0.01
14	Total	50,000,000
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2022-12-31

Year/Period of Report

End of:

2022

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	1,716,226,995
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital	283,148,996
16	MiscellaneousPaidInCapital Ending Balance Amount	1,999,375,991
17	OtherPaidInCapitalAbstract Historical Data - Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19.1	IncreasesDecreasesInOtherPaidInCapital Increases (Decreases) in Other Paid-In Capital
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	1,999,375,991

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2	First Mortgage Bonds 5.71% (Montana)		(a) 55,000,000		549,881			10/15/2009	10/15/2039	10/15/2009	10/15/2039	55,000,000	3,140,500
3	First Mortgage Bonds 5.010% (Montana)		161,000,000		909,702	4,730,180		05/27/2010	05/01/2025	05/27/2010	05/01/2025	161,000,000	8,066,100
4	First Mortgage Bonds 4.15% (Montana)		60,000,000		376,671			08/10/2012	08/10/2042	08/10/2012	08/10/2042	60,000,000	2,490,000
5	First Mortgage Bonds 4.30% (Montana)		40,000,000		251,114			08/10/2012	08/10/2052	08/10/2012	08/10/2052	40,000,000	1,720,000
6	First Mortgage Bonds 4.85% (Montana)		15,000,000		70,047			12/19/2013	12/19/2043	12/19/2013	12/19/2043	15,000,000	727,500
7	First Mortgage Bonds 3.99% (Montana)		35,000,000		163,444			12/19/2013	12/19/2028	12/19/2013	12/19/2028	35,000,000	1,396,500
8	First Mortgage Bonds 4.176% (Montana)		450,000,000		4,927,101			11/14/2014	11/15/2044	11/14/2014	11/15/2044	450,000,000	18,792,000
9	First Mortgage Bonds 3.11% (Montana)		75,000,000		4,137,235			06/23/2015	07/01/2025	07/01/2015	07/01/2025	75,000,000	2,332,500
10	First Mortgage Bonds 4.11% (Montana)		125,000,000		6,895,391			06/23/2015	07/01/2045	07/01/2015	07/01/2045	125,000,000	5,137,500
11	First Mortgage Bonds 4.03% (Montana)		250,000,000		17,138,156			11/06/2017	11/06/2047	11/06/2017	11/06/2047	250,000,000	10,075,000
12	First Mortgage Bonds 3.98% (Montana) A		50,000,000		322,669			06/26/2019	06/26/2049	06/26/2019	06/26/2049	50,000,000	1,990,000
13	First Mortgage Bonds 3.98% (Montana) B		100,000,000		645,339			09/17/2019	09/17/2049	09/17/2019	09/17/2049	100,000,000	3,980,000
14	First Mortgage Bonds 3.21% (Montana)		100,000,000		422,199			05/15/2020	05/15/2030	05/15/2020	05/15/2030	100,000,000	3,210,000
15	First Mortgage Bonds 1.00% (Montana)		100,000,000		557,601			03/26/2021	03/26/2024	03/26/2021	03/26/2024	100,000,000	1,000,000
16	Pollution Control Revenue Bonds - 2.00% Series, City of Forsyth (Montana)		144,660,000		1,590,316			08/11/2016	08/01/2023	08/01/2016	08/01/2023	144,660,000	2,893,200
17	First Mortgage Bonds 5.01% (South Dakota)		64,000,000		412,254	1,880,320		05/27/2010	05/01/2025	05/27/2010	05/01/2025	64,000,000	3,206,400
18	First Mortgage Bonds 4.15% (South Dakota)		30,000,000		184,030			08/10/2012	08/10/2042	08/10/2012	08/10/2042	30,000,000	1,245,000
19	First Mortgage Bonds 4.30% (South Dakota)		20,000,000		122,686			08/10/2012	08/10/2052	08/10/2012	08/10/2052	20,000,000	860,000
20	First Mortgage Bonds 4.85% (South Dakota)		50,000,000		278,988			12/19/2013	12/19/2043	12/19/2013	12/19/2043	50,000,000	2,425,000
21	First Mortgage Bonds 4.22% (South Dakota)		30,000,000		207,702			12/19/2014	12/19/2044	12/19/2014	12/19/2044	30,000,000	1,266,000
22	First Mortgage Bonds 4.26% (South Dakota)		70,000,000		314,529			09/29/2015	09/29/2040	09/29/2015	09/29/2040	70,000,000	2,982,000
23	First Mortgage Bonds 2.80% (South Dakota)		60,000,000		377,548	4,928,484		06/15/2016	06/15/2026	06/15/2016	06/15/2026	60,000,000	1,680,000
24	First Mortgage Bonds 2.66% (South Dakota)		45,000,000		250,872			09/30/2016	09/30/2026	09/30/2016	09/30/2026	45,000,000	1,197,000
25	First Mortgage Bonds 3.21% (South Dakota)		50,000,000		352,905			05/15/2020	05/15/2030	05/15/2020	05/15/2030	50,000,000	1,605,000
26	Subtotal		2,179,660,000		41,458,380	11,538,984						2,179,660,000	83,417,200
27	Reacquired Bonds (Account 222)
28
29
30
31	Subtotal
32	Advances from Associated Companies (Account 223)
33
34
35
36	Subtotal
37	Other Long Term Debt (Account 224)
38	Senior Unsecured Revolving Line of Credit ($425m)		425,000,000					05/18/2022	05/18/2027	05/18/2022	05/18/2027	425,000,000	11,681,250
39	Senior Unsecured Revolving Line of Credit ($25m)		25,000,000					03/25/2022	03/27/2024	03/27/2022	03/27/2024	25,000,000	251,562
40	Capital Leases (miscellaneous)												637
41	Interest Rate Hedge Amortizations												613,744
42	Community Development
43	Subtotal		450,000,000									450,000,000	12,547,193
33	TOTAL		2,629,660,000									2,629,660,000	95,964,393

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: BondsPrincipalAmountIssued

As issuances are redeemed, the related expense and premium or discount, as applicable, is charged to Loss on Reacquired Debt.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	183,006,620
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	Equity Earnings of Subsidiaries	668,404
9	Deductions Recorded on Books Not Deducted for Return
10	Meals and Entertainment	14,974
11	Non-Deductible Dues/Lobbying Expense/Penalties/Professional Fees	3,417,449
12	Life Insurance/Reserves and Other Misc. Charges	6,379
13	Federal Income Taxes/State Tax Adjustment	256,220
14	Income Recorded on Books Not Included in Return
15
16
17
18
19	Deductions on Return Not Charged Against Book Income
20	Net Tax Greater Than Book Depreciation	15,737,449
21	Amortization of Intangibles	215,461
22	Plant Flow Through Items	119,284,756
23	Reserves & Accruals	54,220,265
24	Deferred Book Revenue & Gains	8,320,780
25	Contributions & Advances for Construction	18,782,590
26	Other Miscellaneous	6,710,310
27	Federal Tax Net Income	63,200,693
28	Show Computation of Tax:
29	Federal Tax Expense/(Benefit) @ 21%	13,272,146

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1	FICA and Medicare	Federal Tax	Montana	2022	7	0	9,685,745	9,685,738		0		5,104,012			4,581,733
2	FICA and Medicare	Federal Tax	South Dakota	2022	0	0	2,230,536	2,230,536		0		764,544			1,465,992
3	Subtotal Federal Tax				7	0	11,916,281	11,916,274	0	0	0	5,868,556	0	0	6,047,725
4	State Income Tax	State Tax	Montana	2022	20,760,130	0	3,033,250	4,904,000	(a) 21,668,805	2,779,425		448,740			2,584,510
5	State Income Tax	State Tax	South Dakota/Nebraska	2022	22,644,641	0	727,667	0	(b) 21,264,088	652,886					727,667
6	Subtotal State Tax				1,884,511	0	3,760,917	4,904,000	404,717	3,432,311	0	448,740	0	0	3,312,177
7					0	0				0
8	Subtotal Local Tax				0	0	0	0	0	0	0	0	0	0	0
9	Hydro Invasive Species Tax	Other Taxes	Montana	2021	178,251	0		178,251		0
10	Hydro Invasive Species Tax	Other Taxes	Montana	2022	0	0	712,999	534,749		178,250		712,999
11	Heavy Highway Tax	Other Taxes	Montana	2022	0	0	16,267	16,267		0		11,224			5,043
12	Personal Property - Auto	Other Taxes	Montana	2022	0	0	5,736	5,736		0		0			5,736
13	WET Tax	Other Taxes	Montana	2021	426,093	0		426,093		0
14	WET Tax	Other Taxes	Montana	2022	0	0	1,770,136	1,313,684		456,452		1,426,403			343,733
15	EELT Tax	Other Taxes	Montana	2021	202,259	0		202,259		0
16	EELT Tax	Other Taxes	Montana	2022	0	0	885,727	639,636		246,091		885,727
17	Consumer Counsel	Other Taxes	Montana	2021	158,381	0		158,381		0
18	Consumer Counsel	Other Taxes	Montana	2022	0	0	651,697	515,626		136,071		419,610			232,087
19	Montana Public Service Commission	Other Taxes	Montana	2021	504,440	0		504,440		0
20	Montana Public Service Commission	Other Taxes	Montana	2022	0	0	2,491,286	1,641,837		849,449		1,430,006			1,061,280
21	Gross Receipts Tax	Other Taxes	South Dakota	2021	344,403	0	878	345,281		0					878
22	Gross Receipts Tax	Other Taxes	South Dakota	2022	0	0	393,267			393,267		319,258			74,009
23	Coal Conversion Tax	Other Taxes	North Dakota	2022	0	0	29,816	29,816		0		29,816
24	Subtotal Other Tax				1,813,827	0	6,957,809	6,512,056	0	2,259,580	0	5,235,043	0	0	1,722,766
25	Property Tax	Property Tax	Montana	2021	79,266,640	0		79,266,640		0
26	Property Tax	Property Tax	Montana	2022	0	0	177,166,997	88,658,154		88,508,843		139,115,909			38,051,088
27	Property Tax - Crow Tribe	Property Tax	Montana	2020	209,784	0				209,784
28	Property Tax - Crow Tribe	Property Tax	Montana	2021	209,784	0				209,784
29	Property Tax - Crow Tribe	Property Tax	Montana	2022	0	0	209,784			209,784		84,948			124,836
30	Property Tax - Blackfoot	Property Tax	Montana	2022	0	0	372,576	372,576		0					372,576
31	Property Tax	Property Tax	South Dakota	2021	5,487,115	0	135,263	5,351,852		0		117,909			17,354
32	Property Tax	Property Tax	South Dakota	2022	0	0	5,699,807			5,699,807		5,014,890			684,917
33	Property Tax	Property Tax	Nebraska	2021	667,431	0	27,875	677,414		17,892					27,875
34	Property Tax	Property Tax	Nebraska	2022	0	0	737,062			737,062					737,062
35	Property Tax	Property Tax	North Dakota	2021	16,591	0	262	16,853		0		262
36	Property Tax	Property Tax	North Dakota	2022	0	0	16,413			16,413		16,413
37	Property Tax	Property Tax	Iowa	2020	38,715	0	14	38,730		1		14
38	Property Tax	Property Tax	Iowa	2021	0	0	143,984	72,673		71,311		143,984
39	Property Tax	Property Tax	Iowa	2022	0	0	110,043	0		110,043		110,043
40	Subtotal Property Tax				85,896,060	0	184,349,554	174,454,892	0	95,790,722	0	144,368,554	0	0	39,981,000
41	Subtotal Real Estate Tax				0	0	0	0	0	0	0	0	0	0	0
42	Federal Unemplyment Tax	Unemployment Tax	Montana	2021	1,833	0		1,833		0
43	Federal Unemplyment Tax	Unemployment Tax	Montana	2022	0	0	61,221	59,123		2,098		17,843			43,378
44	Federal Unemplyment Tax	Unemployment Tax	South Dakota	2021	123	0		123		0
45	Federal Unemplyment Tax	Unemployment Tax	South Dakota	2022	0	0	13,892	13,999		107		2,673			11,219
46	State Unemployment Tax	Unemployment Tax	Montana	2021	10,638	0		10,638		0
47	State Unemployment Tax	Unemployment Tax	Montana	2022	0	0	406,522	386,972		19,550		129,491			277,031
48	State Unemployment Tax	Unemployment Tax	South Dakota	2021	235			235		0
49	State Unemployment Tax	Unemployment Tax	South Dakota	2022	0	0	17,726	17,396		330		2,520			15,206
50	Subtotal Unemployment Tax				12,583	0	499,361	490,073	0	21,871	0	152,527	0	0	346,834
51	Use Tax	Sales And Use Tax	Wyoming	2022	0	0	1,275	419		856					1,275
52	Use Tax	Sales And Use Tax	South Dakota	2021	65,888	0		65,888		0
53	Use Tax	Sales And Use Tax	South Dakota	2022	0	0	1,451,005	1,348,880		102,125					1,451,005
54	Subtotal Sales And Use Tax				65,888	0	1,452,280	1,415,187	0	102,981	0	0	0	0	1,452,280
55	Federal Income Tax	Income Tax	Montana	2022	36,393,762	0	7,632,066	0	(c) 33,586,074	10,439,754		218,744			7,413,322
56	Federal Income Tax	Income Tax	South Dakota/Nebraska	2022	42,808,690	0	3,939,609	6,602,890	(d)(e) 40,691,365	12,659,824		2,920,307			6,859,916
57	Subtotal Income Tax				6,414,928	0	3,692,457	6,602,890	7,105,291	2,220,070	0	3,139,051	0	0	553,406
58	Subtotal Excise Tax				0	0	0	0	0	0	0	0	0	0	0
59	Subtotal Fuel Tax				0	0	0	0	0	0	0	0	0	0	0
60	Subtotal Federal Insurance Tax				0	0	0	0	0	0	0	0	0	0	0
61	Delaware Franchise Tax	Franchise Tax	Montana	2022	0	0	207,728	207,728		0		152,668			55,060
62	Delaware Franchise Tax	Franchise Tax	South Dakota	2022	0	0	42,547	42,547		0		25,028			17,519
63	Subtotal Franchise Tax				0	0	250,275	250,275	0	0	0	177,696	0	0	72,579
64	TOTAL				0	0				0
65	Subtotal Miscellaneous Other Tax				0	0	0	0	0	0	0	0	0	0	0
66	Subtotal Other Federal Tax				0	0	0	0	0	0	0	0	0	0	0
67	Subtotal Other State Tax				0	0	0	0	0	0	0	0	0	0	0
68	Subtotal Other Property Tax				0	0	0	0	0	0	0	0	0	0	0
69	Subtotal Other Use Tax				0	0	0	0	0	0	0	0	0	0	0
70	Subtotal Other Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
71	Subtotal Other License And Fees Tax				0	0	0	0	0	0	0	0	0	0	0
72	Subtotal Payroll Tax				0	0	0	0	0	0	0	0	0	0	0
73	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
74	Subtotal Other Allocated Tax				0	0	0	0	0	0	0	0	0	0	0
75	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
76	Subtotal Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
77	Subtotal Other Taxes And Fees				0	0	0	0	0	0	0	0	0	0	0
40	TOTAL				79,488,912	0	212,878,934	206,545,647	6,700,574	(f) 92,522,773	0	(g)(h) 159,390,167	0	0	53,488,767

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: TaxAdjustments

Reclassification of taxes payable to reflect the correct amount for each division.

(b) Concept: TaxAdjustments

Reclassification of taxes payable to reflect the correct amount for each division.

(d) Concept: TaxAdjustments

Federal Refund of Alternative Minimum Tax credit.

(e) Concept: TaxAdjustments

Reclassification of taxes payable to reflect the correct amount for each division.

(f) Concept: TaxesAccrued

Montana Operations unfunded reserves for Taxes Accrued (236) are $88,508,843 and $79,266,640 for 2022 and 2021, respectively.

(g) Concept: TaxesAccruedPrepaidAndCharged


South Dakota Electric - taxes accrued, exclusive of federal and state income taxes	Taxes Charged During the Year 2022
(b)	(c)

Property - South Dakota	$	4,896,980
Property - North Dakota	16,675
Property - Iowa	143,998
Highway Vehicle Use Tax - SD	—
Coal Conversion Facility - N Dakota	29,816
Gross Revenue - South Dakota	319,258
Delaware Franchise	25,028
Vehicle - South Dakota	—
Payroll Tax - FICA	579,995
Payroll Tax - Medicare	184,550
Payroll Tax - FUTA	2,674
Payroll Tax - SUTA - SD	2,521
	$	6,201,495

(h) Concept: TaxesAccruedPrepaidAndCharged


Montana Electric - taxes accrued, exclusive of federal and state income taxes			Taxes Charged During the Year 2022
(b)			(c)
Payroll Tax - FICA			3,871,980
Payroll Tax - Medicare			1,232,032
Payroll Tax - FUTA			17,842
Highway Vehicle Use Tax - MT			11,224
Payroll Tax - SUTA - MT			129,490
Real & Personal Property - Transmission			36,960,840
Real & Personal Property - Production			28,205,280
Real & Personal Property - Distribution			74,034,737
City License Tax - MT			—
WET - Montana			1,426,403
EELT - Montana			885,727
Invasive Species Tax - MT			712,999
Cons Council Tax - MT			419,610
MPSC - Montana			1,430,006
Delaware Franchise			152,668
			149,490,838

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%				411.4
3	4%				411.4
4	7%
5	10%	39			411.4	39
8	TOTAL Electric (Enter Total of lines 2 thru 7)	39				39
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
11	Other - 30	517,929			411.4	(a) 129,482		388,447	5 years
12	OTHER TOTAL	517,929				129,482		388,447
13	Account 255 balance	517,968				129,521		388,447
47	OTHER TOTAL
48	GRAND TOTAL	517,968						388,447

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAmount


The other 30% amount disclosed on Page 266 is comprised of the following amounts:
129,482			Amortization
—			New Credits
129,482			Allocation to Current Year's Income

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Montana Operations:
2	Pension Plan Requirement (Montana)	88,400,501	Various	19,986,660	7,840,036	76,253,877
3	Projects & Studies Prepaid by Customers (Montana)	29,144,187		12,485,147	9,470,013	26,129,053
4	Other Minor Items (9) - some are amortized over various periods (Montana)	8,723,625		5,606,005	1,565,335	4,682,955
5	South Dakota Operations:
6	Family Protector Plan Future Payments (South Dakota)	601,486		301,154		300,332
7	Projects & Studies Prepaid by Customer (South Dakota)	110,839		133,635	30,448	7,652
8	Deferred Directors' Compensation (South Dakota)	18,234,394		7,467,008	10,127,118	20,894,504
9	Other Minor Items (4) - some are amortized over various periods (South Dakota)	2,604,502		494,727	1,536,054	3,645,829
10	Corporate:
11	Minor Item (Corporate)	2,035,306			931,006	2,966,312
12	Permanent Uncertain Tax Positions (Corporate)	23,270,790		1,643,852	1,645,051	23,271,989
47	TOTAL	173,125,630		48,118,188	33,145,061	158,152,503

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)

Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
For other (Specify),include deferrals relating to other income and deductions.
Use footnotes as required.

CHANGES DURING YEAR

ADJUSTMENTS

Debits

Credits

Line No.

Account

(a)

Balance at Beginning of Year

(b)

Amounts Debited to Account 410.1

(c)

Amounts Credited to Account 411.1

(d)

Amounts Debited to Account 410.2

(e)

Amounts Credited to Account 411.2

(f)

Account Credited

(g)

Amount

(h)

Account Debited

(i)

Amount

(j)

Balance at End of Year

(k)

Accelerated Amortization (Account 281)

Electric

Defense Facilities

Pollution Control Facilities

Other

5.1

Other (provide details in footnote):

TOTAL Electric (Enter Total of lines 3 thru 7)

Gas

Defense Facilities

Pollution Control Facilities

Other

12.1

Other (provide details in footnote):

TOTAL Gas (Enter Total of lines 10 thru 14)

Other

16.1

Other

16.2

Other

TOTAL (Acct 281) (Total of 8, 15 and 16)

Classification of TOTAL

Federal Income Tax

State Income Tax

Local Income Tax

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	(a) 380,976,614	25,145,401								406,122,015
3	Gas	67,676,937	1,002,982	2,298,885							66,381,034
4	Other (Specify)	17,308,397	25,489								17,282,908
5	Total (Total of lines 2 thru 4)	431,345,154	26,173,872	2,298,885							455,220,141
6
7
8
9	TOTAL Account 282 (Total of Lines 5 thru 8)	431,345,154	26,173,872	2,298,885							455,220,141
10	Classification of TOTAL
11	Federal Income Tax	431,345,154	20,422,358	1,709,660			282	92,415,959			357,641,893
12	State Income Tax		5,751,514	589,225					282	92,415,959	97,578,248
13	Local Income Tax

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty


Line No	Account	Balance at Beg of Year	Amounts Debited to Account 410.1	Amounts Credited to Account 411.1	Adjustments Debit Amounts	Adjustments Credit Amounts	Balance at End of Year
	(a)	(b)	(c)	(d)	(h)	(j)	(k)
MONTANA
1	Account 282
2	Electric	318,662,495	22,408,354	—			341,070,849
3	Gas	59,171,736	—	(2,298,885)			56,872,851
4	Other	(17,308,396)	25,488	—			(17,282,908)
5	Total	360,525,834	22,433,842	(2,298,885)			380,660,792
6
7
8
9	Total	360,525,834	22,433,842	(2,298,885)			380,660,792
10	Classification Total
11	Federal Income Tax	360,525,834	16,682,329	(1,709,660)	(92,415,959)		283,082,544
12	State Income Tax		5,751,514	(589,225)		92,415,959	97,578,248
13	Local Income Tax

SOUTH DAKOTA
1	Account 282
2	Electric	62,314,119	2,737,047	—			65,051,166
3	Gas	8,505,201	1,002,982	—			9,508,183
4	Other	—	—	—			—
5	Total	70,819,320	3,740,029	—			74,559,349
6
7
8
9	Total	70,819,320	3,740,029	—			74,559,349
10	Classification Total
11	Federal Income Tax	70,819,320	3,740,029	—			74,559,349
12	State Income Tax
13	Local Income Tax

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Regulatory Assets	(a) 37,127,542	10,292,899	2,400,561							45,019,880
4	Excess Tax Depreciation	75,214,004			10,111,705						85,325,709
9	TOTAL Electric (Total of lines 3 thru 8)	112,341,546	10,292,899	2,400,561	10,111,705						130,345,589
10	Gas
11	Regulatory Assets	16,250,138	2,315,482	1,906,134							16,659,486
12	Excess Tax Depreciation	17,288,057			2,361,991						19,650,048
17	TOTAL Gas (Total of lines 11 thru 16)	33,538,195	2,315,482	1,906,134	2,361,991						36,309,534
18	TOTAL Other	91,689,157			206,750	1,752,880		5,555,256		3,155,749	87,743,520
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	237,568,898	12,608,381	4,306,695	12,680,446	1,752,880		5,555,256		3,155,749	254,398,643
20	Classification of TOTAL
21	Federal Income Tax	213,097,410	9,454,633	4,306,695	9,762,401	126,913		30,538,581		1,388,021	198,730,276
22	State Income Tax	24,471,488	3,153,748		2,918,045	1,625,967		5,555,256		32,306,309	55,668,367
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther


MONTANA
Line No	Account (a)	Balance at Beg of Year (b)	Amounts Debited to Acct 410.1 (c)	Accounts Credited to Acct 411.1 (d)	Amounts Debited to Acct 410.2 (e)	Amounts Credit to Acct 411.2 (f)	Adjustments Debited to Acct 410.2 (e)	Adjustments Credit to Acct 410.2 (f)	Balance at End of Year (k)
1	Account 283
2	Electric:
4	Regulatory Assets	33,504,119	10,292,899	—	—	—	—	—	43,797,018
10	Excess Tax Depreciation	67,905,060	—	—	9,088,892	—	—	—	76,993,952
14	Total Electric	101,409,179	—	—	9,088,892	—	—	—	120,790,970

16	Gas:
18	Regulatory Assets	11,017,064	2,315,483	—	—	—	—	—	13,332,547
24	Excess Tax Depreciation	15,570,231	—	—	1,945,889	—	—	—	17,516,120
27	Total Gas	26,587,295	2,315,483	—	1,945,889	—	—	—	30,848,667

29	Other, Net	91,689,158	—	—	86,713	—	—	1,767,727	93,543,598

31	Total (Acct 283) (Lines 9,17 & 18)	219,685,632	2,315,483	—	11,121,494	—	—	1,767,727	245,183,235

33	Classification of Total
34	Federal Income Tax	195,214,143	9,454,633	—	8,203,449	—	30,538,580	—	182,333,645
35	State Income Tax	24,471,488	3,153,748	—	2,918,045	—		32,306,309	62,849,590
36	Local Income Tax
37		219,685,631	12,608,381	—	11,121,494	—			245,183,235

SOUTH DAKOTA
1	Account 283
2	Electric:
4	Regulatory Assets	3,623,424	—	2,400,562	—	—	—	—	1,222,862
10	Excess Tax Depreciation	7,308,944	—	—	1,022,813	—	—	—	8,331,757
14	Total Electric	10,932,368	—	2,400,562	1,022,813	—	—	—	9,554,619
							—	—
16	Gas:						—	—
18	Regulatory Assets	5,233,073	—	1,906,134	—	—	—	—	3,326,939
24	Excess Tax Depreciation	1,717,825	—	—	416,103	—	—	—	2,133,928
27	Total Gas	6,950,898	—	1,906,134	416,103	—	—	—	5,460,867
		—							—
29	Other, Net	—	—	—	—	126,913	—	—	(126,913)

31	Total (Acct 283) (Lines 9,17 & 18)	17,883,266	—	4,306,696	1,438,916	126,913	—	—	14,888,573

33	Classification of Total
34	Federal Income Tax	17,883,266	—	4,306,696	1,438,916	126,913	—	—	14,888,573
35	State Income Tax
36	Local Income Tax
37		17,883,266	—	4,306,696	1,438,916	126,913			14,888,573

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Excess Deferred Income Taxes (Montana)	137,027,734		8,045,190	83,792	(a) 129,066,336
2	Deferred Gas Storage Sales (Montana) - Docket D2001.1.1; Amortization 2001 - 2039	7,466,461	(2)407	420,517		7,045,944
3	Montana Public Service Commission Consumer Counsel Taxes (Montana) - Dockets 2017.9.78 and 2018.10.67	1,694,066	Various	85,057	299,891	1,908,900
4	CTC QF Over/Under Collections (Montana) - Docket 97.9.90 and Docket 2001.1.15; Annual Amortization	29,377		353,376	1,080,324	756,325
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	571,311		4,124,618	3,553,306	1
6	Natural Gas Regulatory Deferrals (Montana)	269,044		420,808	179,320	27,556
7	Excess Deferred Income Taxes (South Dakota)	21,019,531	(2)407	1,096,670		(b) 19,922,861
8	Current Ad Valorem True-Up (South Dakota) - Docket GE98-001	486,128	(2)407	350,261	254,447	390,314
9	Aberdeen Manufactured Gas Plant (South Dakota) - Docket NG 11-003	508,123		48,136	131,562	591,549
10	Tax Cut Jobs Act Deferral (South Dakota) - Docket NG-0095 and GE17-003	155,000				155,000
11	Unbilled Revenues (South Dakota)	16,429,994		8,288,824	3,394,948	11,536,118
41	TOTAL	185,656,769		23,233,457	8,977,590	171,400,902

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilities


Line No.	Description (a)	(b)	(c)	(d)	(e)	(f)	(g)

	MONTANA:
		12/31/2021
		Protected	Unprotected			Normalizing EDIT
	TCJA Excess ADIT Account Reduced	282	283	Subtotal	Total 182.3	282	FERC Unamortized
	Reg Asset Acccount Impacted	254	254	254	and 254	254	Total
1	Electric:
2	Regulatory Assets / Liabilities		1,814,724	1,814,724	1,806,383	—	1,806,383
3	Unbilled Revenue		—	—	687,232	—	687,232
4	Compensation Accruals		—	—	751,386	—	751,386
5	Reserves & Accruals		—	—	179,940	—	179,940
6	Intangible amortization		(7,953,915)	(7,953,915)	(7,953,915)	—	(7,953,915)
7	Pension / Postretirement Benefits		—	—	4,927,736	—	4,927,736
8	Environmental Liability		—	—	264,469	—	264,469
9	Interest Rate Hedge		—	—	—	—	—
10	Customer Advances		—	—	2,329,891	—	2,329,891
11	Excess tax Depreciation / Other Property	(72,248,710)	—	(72,248,710)	(72,248,710)	(24,561,561)	(96,810,271)
12	Net Operating Loss			—	26,940,081	—	26,940,081
13	Total Electric	(72,248,710)	(6,139,191)	(78,387,901)	(42,315,507)	(24,561,561)	(66,877,068)
14	Gas:
15	Regulatory Assets / Liabilities		(2,112,982)	(2,112,982)	(2,138,623)	—	(2,138,623)
16	Unbilled Revenue		—	—	534,514	—	534,514
17	Compensation Accruals		—	—	584,411	—	584,411
18	Reserves & Accruals		—	—	116,195	—	116,195
19	Intangible amortization		(3,105,059)	(3,105,059)	(3,105,059)	—	(3,105,059)
20	Pension / Postretirement Benefits		—	—	3,834,145	—	3,834,145
21	Environmental Liability		—	—	205,698	—	205,698
22	Interest Rate Hedge		—	—	—	—	—
23	Customer Advances		—	—	1,264,062	—	1,264,062
24	Excess tax Depreciation / Other Property	(17,338,964)	—	(17,338,964)	(17,338,964)	(7,078,524)	(24,417,488)
25	Net Operating Loss			—	(3,503,486)	—	(3,503,486)
26	Total Gas	(17,338,964)	(5,218,041)	(22,557,005)	(19,547,107)	(7,078,524)	(26,625,631)
27	Other (Specify)	—	—	—	498,848	211,270	710,118
28	Subtotal	(89,587,674)	(11,357,232)	(100,944,906)	(61,363,766)	(31,428,815)	(92,792,581)
29	Gross-up	(32,023,178)	(4,059,650)	(36,082,828)	(21,934,522)	(11,234,252)	(33,168,774)
30	Total	(121,610,852)	(15,416,882)	(137,027,734)	(83,298,288)	(42,663,067)	(125,961,355)
31
32	Other (Specify)
33	QF Obligations	—	—	—	—	—	—
34	NOL Carryforward	—	—	—	—	—	—
35	AMT Credit Carryforward	—	—	—	—	—	—
36	Production Tax Credit	—	—	—	—	—	—
37	Regulatory Assets / Liabilities	—	—	—	—	—	—
38	Other, net	—	—	—	498,848	211,270	710,118
39	Total	—	—	—	498,848	211,270	710,118
40


41
42		12/31/2022
43		Protected	Unprotected			Normalizing EDIT
44	TCJA Excess ADIT Account Reduced	282	283	Subtotal	Total of 182.3	Subtotal	282
45	Reg Asset Acccount Impacted	254	254	254	and 254	182.3	254
46	Electric:
47	Regulatory Assets / Liabilities		1,080,161	1,080,161	1,083,832	—	1,083,832
48	Unbilled Revenue		—	—	412,339	—	412,339
49	Compensation Accruals		—	—	450,831	—	450,831
50	Reserves & Accruals		—	—	107,964	—	107,964
51	Intangible amortization		(4,772,349)	(4,772,349)	(4,772,349)	—	(4,772,349)
52	Pension / Postretirement Benefits		—	—	2,956,642	—	2,956,642
53	Environmental Liability		—	—	158,682	—	158,682
54	Interest Rate Hedge		—	—	—	—	—
55	Customer Advances		—	—	1,397,935	—	1,397,935
56	Excess Tax Depreciation / Other Property	(69,779,321)	—	(69,779,321)	(69,779,321)	(14,736,937)	(84,516,258)
57	Net Operating Loss			—	26,018,461	—	26,018,461
58	Total Electric	(69,779,321)	(3,692,188)	(73,471,509)	(41,964,984)	(14,736,937)	(56,701,921)
59	Gas:
60	Regulatory Assets / Liabilities		(2,112,982)	(2,112,982)	(2,138,623)	—	(2,138,623)
61	Unbilled Revenue		—	—	534,514	—	534,514
62	Compensation Accruals		—	—	584,411	—	584,411
63	Reserves & Accruals		—	—	116,195	—	116,195
64	Intangible amortization		(3,105,058)	(3,105,058)	(3,105,058)	—	(3,105,058)
65	Pension / Postretirement Benefits		—	—	3,834,145	—	3,834,145
66	Environmental Liability		—	—	205,698	—	205,698
67	Interest Rate Hedge		—	—	—	—	—
68	Customer Advances		—	—	1,264,062	—	1,264,062
69	Excess Tax Depreciation / Other Property	(16,034,101)	—	(16,034,101)	(16,034,101)	(4,247,115)	(20,281,216)
70	Net Operating Loss			—	(3,384,786)	—	(3,384,786)
71	Total Gas	(16,034,101)	(5,218,040)	(21,252,141)	(18,123,543)	(4,247,115)	(22,370,658)
72	Other (Specify)	(356,293)	—	(356,293)	(37,042)	163,735	126,693
73	Subtotal	(86,169,715)	(8,910,228)	(95,079,943)	(60,125,569)	(18,820,317)	(78,945,886)
74	Gross-up	(30,801,426)	(3,184,967)	(33,986,393)	(21,491,927)	(6,727,336)	(28,219,263)
75	Total	(116,971,141)	(12,095,195)	(129,066,336)	(81,617,496)	(25,547,653)	(107,165,149)
76
77	Other (Specify)
78	QF Obligations	—	—	—	—	—	—
79	NOL Carryforward	—	—	—	—	—	—
80	AMT Credit Carryforward	—	—	—	—	—	—
81	Production Tax Credit	—	—	—	—	—	—
82	Regulatory Assets / Liabilities	—	—	—	—	—	—
83	Other, net	(356,293)	—	(356,293)	(37,042)	163,735	126,693
84	Total	(356,293)	—	(356,293)	(37,042)	163,735	126,693
85
86
87	SOUTH DAKOTA:
88		12/31/2021
89		Protected	Unprotected			Normalizing EDIT
90	TCJA Excess ADIT Account Reduced	282	283	Subtotal	Total 182.3	282	FERC Unamortized


91	Reg Asset Acccount Impacted	254	254	254	and 254	254	Total
92	Electric:
93	Regulatory Assets / Liabilities		—	—	—	—	—
94	Unbilled Revenue		—	—	—	—	—
95	Compensation Accruals		—	—	—	—	—
96	Reserves & Accruals		—	—	—	—	—
97	Intangible amortization		—	—	—	—	—
98	Pension / Postretirement Benefits		—	—	—	—	—
99	Environmental Liability		—	—	—	—	—
100	Interest Rate Hedge		—	—	—	—	—
101	Customer Advances		—	—	—	—	—
102	Excess tax Depreciation / Other Property	(14,997,688)	—	(14,997,688)	(14,997,688)	(13,466,337)	(28,464,025)
103	Net Operating Loss			—	4,001,825	—	4,001,825
104	Total Electric	(14,997,688)	—	(14,997,688)	(10,995,863)	(13,466,337)	(24,462,200)
105	Gas:
106	Regulatory Assets / Liabilities		(238,951)	(238,951)	(238,951)	—	(238,951)
107	Unbilled Revenue		—	—	237,268	—	237,268
108	Compensation Accruals		—	—	895,742	—	895,742
109	Reserves & Accruals		—	—	66,862	—	66,862
110	Intangible amortization		—	—	—	—	—
111	Pension / Postretirement Benefits		—	—	(67,853)	—	(67,853)
112	Environmental Liability		—	—	491,773	—	491,773
113	Interest Rate Hedge		—	—	—	—	—
114	Customer Advances		—	—	—	—	—
115	Excess tax Depreciation / Other Property	(1,370,509)	—	(1,370,509)	(1,370,509)	(2,174,569)	(3,545,078)
116	Net Operating Loss			—	(159,752)	—	(159,752)
117	Total Gas	(1,370,509)	(238,951)	(1,609,460)	(145,420)	(2,174,569)	(2,319,989)
118	Other (Specify)	—	1,719	1,719	131,649	—	131,649
119	Subtotal	(16,368,197)	(237,232)	(16,605,429)	(11,009,634)	(15,640,906)	(26,650,540)
120	Gross-up	(4,351,040)	(63,062)	(4,414,102)	(2,926,612)	(4,157,709)	(7,084,321)
121	Total	(20,719,237)	(300,294)	(21,019,531)	(13,936,246)	(19,798,615)	(33,734,861)
122
123	Other (Specify)
124	QF Obligations	—	—	—	—	—	—
125	NOL Carryforward	—	—	—	—	—	—
126	AMT Credit Carryforward	—	—	—	—	—	—
127	Production Tax Credit	—	—	—	—	—	—
128	Regulatory Assets / Liabilities	—	—	—	—	—	—
129	Other, net	—	1,719	1,719	131,649	—	131,649
130	Total	—	1,719	1,719	131,649	—	131,649
131
132
133		12/31/2022
134		Protected	Unprotected			Normalizing EDIT
135	TCJA Excess ADIT Account Reduced	282	283	Subtotal	Total 182.3	282	FERC Unamortized
136	Reg Asset Account Impacted	254	254	254	and 254	254	Total
137	Electric:
138	Regulatory Assets / Liabilities		—	—	—	—	—
139	Unbilled Revenue		—	—	—	—	—
140	Compensation Accruals		—	—	—	—	—
141	Reserves & Accruals		—	—	—	—	—


142	Intangible amortization		—	—	—	—	—
143	Pension / Postretirement Benefits		—	—	—	—	—
144	Environmental Liability		—	—	—	—	—
145	Interest Rate Hedge		—	—	—	—	—
146	Customer Advances		—	—	—	—	—
147	Excess Tax Depreciation / Other Property	(14,378,122)	—	(14,378,122)	(14,378,122)	(13,001,493)	(27,379,615)
148	Net Operating Loss			—	3,863,687	—	3,863,687
149	Total Electric	(14,378,122)	—	(14,378,122)	(10,514,435)	(13,001,493)	(23,515,928)
150	Gas:
151	Regulatory Assets / Liabilities		(238,951)	(238,951)	(238,951)	—	(238,951)
152	Unbilled Revenue		—	—	237,268	—	237,268
153	Compensation Accruals		—	—	895,742	—	895,742
154	Reserves & Accruals		—	—	66,861	—	66,861
155	Intangible amortization		—	—	—	—	—
156	Pension / Postretirement Benefits		—	—	(67,853)	—	(67,853)
157	Environmental Liability		—	—	491,773	—	491,773
158	Interest Rate Hedge		—	—	—	—	—
159	Customer Advances		—	—	—	—	—
160	Excess Tax Depreciation / Other Property	(1,123,706)	—	(1,123,706)	(1,123,706)	(2,099,506)	(3,223,212)
161	Net Operating Loss			—	(154,239)	—	(154,239)
162	Total Gas	(1,123,706)	(238,951)	(1,362,657)	106,895	(2,099,506)	(1,992,611)
163	Other (Specify)	—	1,719	1,719	131,649	—	131,649
164	Subtotal	(15,501,828)	(237,232)	(15,739,060)	(10,275,891)	(15,100,999)	(25,376,890)
165	Gross-up	(4,120,739)	(63,062)	(4,183,801)	(2,731,566)	(4,014,190)	(6,745,756)
166	Total	(19,622,567)	(300,294)	(19,922,861)	(13,007,457)	(19,115,189)	(32,122,646)
167
168	Other (Specify)
169	QF Obligations	—	—	—	—	—	—
170	NOL Carryforward	—	—	—	—	—	—
171	AMT Credit Carryforward	—	—	—	—	—	—
172	Production Tax Credit	—	—	—	—	—	—
173	Regulatory Assets / Liabilities	—	—	—	—	—	—
174	Other, net	—	1,719	1,719	131,649	—	131,649
175	Total	—	1,719	1,719	131,649	—	131,649

(b) Concept: OtherRegulatoryLiabilities

Refer to footnote at column (f) line 1 for details.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	426,147,770	396,667,149	3,463,605	3,299,444	368,037	362,727
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	454,204,813	437,220,984	3,861,758	3,795,835	87,947	86,266
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	74,495,380	69,905,103	756,160	721,224	138	141
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	16,226,737	16,574,818	40,667	46,169	3,771	3,788
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	894,925	797,869	7,275	6,652	274	272
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales	879,131	858,550	7,442	7,525	342	342
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	972,848,756	922,024,473	8,136,907	7,876,849	460,509	453,536
11	SalesForResaleAbstract (447) Sales for Resale	51,420,884	31,170,156	1,058,843	957,499
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	1,024,269,640	953,194,629	9,195,750	8,834,348	460,509	453,536
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	1,979,898	5,161,502
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	1,026,249,538	958,356,131	9,195,750	8,834,348	460,509	453,536
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	462,318	435,650
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	214,473	221,410
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	(a) 4,372,406	4,001,542
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 17,510,620	14,003,869
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	78,400,732	81,029,963
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
25.1	OtherMiscellaneousOperatingRevenues (Less) (449.1) Provision for Rate Refunds		4,711,241
26	OtherOperatingRevenues TOTAL Other Operating Revenues	100,960,549	104,403,675
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	(c) 1,127,210,087	1,062,759,806
Line12, column (b) includes $ 56,420,176 of unbilled revenues.
Line12, column (d) includes 460,917 MWH relating to unbilled revenues

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: RentFromElectricProperty

Rent from South Dakota electric property was $223,992 and $177,688 for 2022 and 2021, respectively.

Rent from Montana electric property was $4,148,415 and$3,823,854 for 2022 and 2021, respectively.

(b) Concept: OtherElectricRevenue


	YTD Dec				Montana Operations
Total Electric Revenue	2022		2021		2022		2021
Rate Revenue	972,848,756		922,024,473		792,105,531		751,527,178
Sales for Resale & Coops	51,420,884		31,170,156		51,420,884		31,170,156
Provision for Rate Refund - MPSC	—		5,161,502		—		5,161,502
Provision for Rate Refund - FERC	1,979,898		4,711,241		1,979,898		4,711,241
Forfeited Discounts	462,318		435,650		—		—
Service Revenue	214,473		221,410		(2,835)		—
Rent	4,372,406		4,001,542		4,148,415		3,823,854
Transmission (456.1)	78,011,672		80,695,683		71,875,119		73,964,512
SPP Sch 7-8 Form Rate	389,060		334,280		—		—
Other	17,510,620		14,003,869		16,568,629		13,621,747
	1,127,210,087		1,062,759,806		938,095,641		883,980,190

	YTD Dec		YTD Dec		Montana Operations
Other Electric Revenue (456)	2022		2021		2022		2021
Ancillary Services:
Scheduling, System Control and Dispatch	$	1,875,805	$	1,837,058	$	1,875,805	$	1,837,059
Regulation and Frequency Response	1,131,370		1,161,969		1,131,370		1,161,970
Energy Imbalance	8,972,921		6,293,506		8,972,921		6,293,506
Other Transmission Revenue	1,150,552		1,502,297		1,150,552		1,502,297
Low Income Housing	2,354,251		2,281,343		2,354,251		2,281,343
Steam Sales	920,670		351,230		—		—
Sale of Materials	67,902		56,376		46,746		26,914
Miscellaneous	1,037,149		520,090		1,036,984		518,658
	$	17,510,620	$	14,003,869	$	16,568,629	$	13,621,747


Montana Operations
Line No.	Account (a)	Operating Revenues Year to Date (b)	MWH Sold Year to Date (d)	Current Year Ave. No. of Customers (f)
2	(440) Residential Sales	356,338,844	2,867,229	316,968
4	(442) Small Commercial and Industrial	380,801,589	3,203,588	75,112
5	(442) Large Commercial and Industrial	39,696,380	300,270	76
6	(444) Public Street and Highway Lighting	14,389,588	28,799	3,625
9	(448) Interdepartmental Sales	879,130	7,441	342
10	TOTAL Sales to Ultimate Consumers	792,105,531	6,407,327	396,123
11	(447) Sales for Resale	51,420,884
12	Total Sales of Electricity	843,526,415
13	(449.1) Provision for Transmission Rate Refund	(1,980,680)
14	Total Revenues Net of Prov. For Refunds	845,507,095
16	(450) Forfeited Discounts
17	(451) Miscellaneous Service Revenue	(2,834)
19	(454) Rent from Electric Property	4,148,415
21	(456) Other Electric Revenues	16,568,629
22	(456.1) Transmission of Electricity for Others	71,875,119
25	(449.1) Provision for Transmission Rate Refund	—
26	TOTAL Other Operating Revenues	92,589,329
27	TOTAL Electric Operating Revenues	938,096,424

	Line 12, column (b) includes $	56,420,176	of unbilled revenues
	Line 12, column (d) includes	460,917	MWH relating to unbilled rev

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	SD 10 Residential	395,117	49,373,790	39,101	10,105	0.1250
2	SD 11 Resid Space Htg 1 Meter	184,885	19,163,874	10,896	16,968	0.1037
3	SD 14 Resid Space Htg 2 Meters	14,805	1,037,349	1,032	14,346	0.0701
4	SD 15 Residential Dual-Fuel	88	5,863	7	12,571	0.0666
5	SD 95 Reddy Guard	1,481	228,050	33	44,879	0.1540
6	MT Residential	2,644,997	327,805,001	316,968	8,345	0.1239
7	MT Unbilled Revenue	222,232	28,533,843
41	TOTAL Billed Residential Sales	3,241,373	397,613,927	368,037	8,807	0.1227
42	TOTAL Unbilled Rev. (See Instr. 6)	222,232	28,533,843
43	TOTAL	3,463,605	426,147,770	368,037	9,411	0.1230

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	SD 16 Inter Irrigation	2,645	266,166	68	38,897	0.1006
2	SD 17 Irrigation Power	359	51,752	16	22,438	0.1442
3	SD 21 General Service	73,225	11,626,328	8,589	8,525	0.1588
4	SD 23 Comm Water Heat	566	54,804	59	9,593	0.0968
5	SD 24 Comm Space Heat	42,250	3,019,550	586	72,099	0.0715
6	SD 25 Comm Heating	40,431	4,130,131	802	50,413	0.1022
7	SD 33 Industrial Power	161,419	21,782,951	2,095	77,050	0.1349
8	SD 34 Industrial Power	332,880	31,606,348	426	781,408	0.0949
9	SD 70 Controlled Off-Peak	834	108,620	3	278,000	0.1302
10	SD 73 Small Qual Facil Rider, 38 P to P		226,995	15		0.0000
11	SD 95 Reddy Guard	3,560	529,579	176	20,227	0.1488
12	MT General Service - 1	2,888,320	343,103,396	73,093	39,516	0.1188
13	MT Irrigation	103,551	12,999,841	2,019	51,288	0.1255
14	MT General Service - 1 Unbilled	211,718	24,698,352
41	TOTAL Billed Small or Commercial	3,650,040	429,506,461	87,947	41,503	0.1177
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	211,718	24,698,352
43	TOTAL Small or Commercial	3,861,758	454,204,813	87,947	43,910	0.1176

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	SD 34 Large Industrial	455,890	34,799,000	62	7,353,065	0.0763
2	MT General Service - 2	273,303	36,508,399	76	3,596,092	0.1336
3	MT General Service - 2 Unbilled	26,967	3,187,981
41	TOTAL Billed Large (or Ind.) Sales	729,193	71,307,399	138	5,284,007	0.0978
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	26,967	3,187,981
43	TOTAL Large (or Ind.)	756,160	74,495,380	138	5,479,420	0.0985

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Commercial and Industrial Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	SD 95 Public Lighting	11,868	1,837,149	146	81,288	0.1548
2	MT Lighting	28,799	14,389,588	3,625	7,945	0.4997
41	TOTAL Billed Public Street and Highway Lighting	40,667	16,226,737	3,771	10,784	0.3990
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	40,667	16,226,737	3,771	10,784	0.3990

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	SD 41 Municipal Pumping	7,275	894,925	274	26,551	0.1230
41	TOTAL Billed Other Sales to Public Authorities	7,275	894,925	274	26,551	0.1230
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	7,275	894,925	274	26,551	0.1230

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Interdepartmental	7,442	879,131	342	21,760	0.1181
41	TOTAL Billed Interdepartmental Sales	7,442	879,131	342	21,760	0.1181
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	7,442	879,131	342	21,760	0.1181

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Provision for Rate Refunds		1,979,898
41	TOTAL Billed Provision For Rate Refunds		1,979,898
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL		1,979,898

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	7,675,990	916,428,580	460,509	16,668	0.1194
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	460,917	56,420,176
43	TOTAL - All Accounts	8,136,907	972,848,756	460,509	16,668	0.1267

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 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). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	MONTANA
2	RESERVE SHARING SALES
3	AVISTA Corporation	LF	Reserve Energy	0	0	0	23		3,057		3,057
4	BC HYDRO DISTRIBUTION	LF	Reserve Energy	0	0	0	54		3,189		3,189
5	BONNEVILLE POWER ADMINISTRATION	LF	Reserve Energy	0	0	0	75		2,573		2,573
6	GRID FORCE ENERGY MANAGEMENT, LLC	LF	Reserve Energy	0	0	0	336		20,210		20,210
7	GRANT COUNTY PUD	LF	Reserve Energy	0	0	0	4		199		199
8	PACIFICORP	LF	Reserve Energy	0	0	0	53		3,572		3,572
9	PORTLAND GENERAL ELECTRIC COMPANY	LF	Reserve Energy	0	0	0	21		1,063		1,063
10	NATURENER GLACIER WIND	LF	Reserve Energy	0	0	0	12		533		533
11	NATURENER WIND WATCH	LF	Reserve Energy	0	0	0	35		912		912
12	TALEN MONTANA, LLC	LF	Reserve Energy	0	0	0	262		20,091		20,091
13	IDAHO POWER COMPANY	LF	Reserve Energy	0	0	0	38		3,223		3,223
14	PUGET SOUND ENERGY, INC	LF	Reserve Energy				7		1,342		1,342
15	SACRAMENTO MUNICIPAL UTILITY DISTRICT	LF	Reserve Energy				13		590		590
16	CHELAN COUNTY PUD	LF	Reserve Energy	0	0	0	6		226		226
17	SEATTLE CITY LIGHT	LF	Reserve Energy	0	0	0	2		74		74
18	AVANGRID	LF	Reserve Energy	0	0	0	44		4,841		4,841
19	TRULOCK IRRIGATION DISTRICT	LF	Reserve Energy				3		204		204
20	SUPPLY
21	Avangrid Renewables, LLC	SF	Market-Based Rate				37,218		2,318,245		2,318,245
22	Avista Corporation	SF	Market-Based Rate				28,327		981,775		981,775
23	Basin Electric Power Cooperative	SF	Market-Based Rate				75		4,875		4,875
24	Black Hills Power Inc	SF	Market-Based Rate				8,335		298,371		298,371
25	Bonneville Power Administration	SF	Market-Based Rate				74,872		3,190,585		3,190,585
26	Clatskanie Peoples Utility District - Electric	SF	Market-Based Rate				7,042		405,905		405,905
27	Dynasty Power, Inc.	SF	Market-Based Rate				9,058		477,965		477,965
28	EDF Trading North America, LLC	SF	Market-Based Rate				5,484		186,552		186,552
29	Energy Keepers, Inc.	SF	Market-Based Rate				5,257		300,169		300,169
30	Eugene Water & Electric Board	SF	Market-Based Rate				23,587		1,206,358		1,206,358
31	Exelon Generation Company, LLC	SF	Market-Based Rate				1,407		72,584		72,584
32	Guzman Energy, LLC	SF	Market-Based Rate				18,818		706,483		706,483
33	Heartland Generation LTD	SF	Market-Based Rate				1,000		75,000		75,000
34	Idaho Power Company	SF	Market-Based Rate				205		4,715		4,715
35	Macquarie Energy LLC	SF	Market-Based Rate				117,706		5,900,995		5,900,995
36	Morgan Stanley Capital Group, Inc.	SF	Market-Based Rate				162,626		8,413,069		8,413,069
37	Pacificorp	SF	Market-Based Rate				770		70,225		70,225
38	Phillips 66 Company	SF	Market-Based Rate				1,030		39,475		39,475
39	Portland General Electric	SF	Market-Based Rate				59,226		2,593,191		2,593,191
40	Powerex Corporation	SF	Market-Based Rate				18,559		683,170		683,170
41	Puget Sound Energy	SF	Market-Based Rate				26,994		1,368,235		1,368,235
42	Rainbow Energy Marketing Corporation	SF	Market-Based Rate				16,288		736,756		736,756
43	Seattle City Light	SF	Market-Based Rate				19,242		948,393		948,393
44	Shell Energy North America (US), L.P.	SF	Market-Based Rate				306,039		15,143,596		15,143,596
45	Tacoma Power	SF	Market-Based Rate				8,411		418,570		418,570
46	Tenaska Power Services	SF	Market-Based Rate				963		58,887		58,887
47	The Energy Authority, Inc.	SF	Market-Based Rate				44,535		2,351,577		2,351,577
48	Tiber Montana, LLC	LU	Market-Based Rate				24,887		1,028,884		1,028,884
49	TransAlta Energy Marketing (US) Inc.	SF	Market-Based Rate				28,789		1,320,165		1,320,165
50	Vitol Inc.	SF	Market-Based Rate				125		10,000		10,000
51	Western Area Power Administration	SF	Market-Based Rate				980		40,215		40,215
15	Subtotal - RQ
16	Subtotal-Non-RQ						1,058,843		51,420,884		51,420,884
17	Total						1,058,843		51,420,884		51,420,884

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	(a) 786,697	836,325
5	FuelSteamPowerGeneration (501) Fuel	(b) 54,117,061	44,346,023
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	2,737,648	3,516,005
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	1,213,454	802,830
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	3,581,075	3,470,784
11	RentsSteamPowerGeneration (507) Rents	29,365	33,465
12	Allowances (509) Allowances
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	62,465,300	53,005,432
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	1,128,801	1,255,207
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	1,068,468	1,006,898
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	6,817,890	9,435,528
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	2,009,348	2,285,341
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	971,371	871,492
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	11,995,878	14,854,466
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	74,461,178	67,859,898
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering	678,516	613,183
45	WaterForPower (536) Water for Power	949,611	942,963
46	HydraulicExpenses (537) Hydraulic Expenses	3,654,685	3,804,078
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	3,662,440	3,315,093
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	2,903,754	3,269,367
49	RentsHydraulicPowerGeneration (540) Rents	808,040	788,771
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	12,657,046	12,733,455
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering	560,467	517,919
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	715,688	683,786
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	612,490	758,707
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	1,228,566	1,006,837
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	215,886	540,433
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	3,333,097	3,507,682
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	15,990,143	16,241,137
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	722,188	657,935
63	Fuel (547) Fuel	33,724,390	23,477,997
64	GenerationExpenses (548) Generation Expenses	8,025,712	7,456,228
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	2,406,135	1,230,946
66	RentsOtherPowerGeneration (550) Rents
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	44,878,425	32,823,106
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering	50,511	26,695
70	MaintenanceOfStructures (552) Maintenance of Structures	158,104	64,563
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	2,441,596	2,039,101
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	75,545	149,348
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	2,725,756	2,279,707
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	47,604,181	35,102,813
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	289,399,612	257,640,492
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	304,469	280,190
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	(c) 39,066,467	49,075,418
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	250,637,614	208,845,264
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	388,693,116	328,049,112
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	2,639,609	2,795,081
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	936,249	815,676
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	1,029,220	950,216
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	1,357,193	1,213,918
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	94,637	88,280
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
93	StationExpensesTransmissionExpense (562) Station Expenses	1,614,827	1,541,330
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	1,359,806	1,482,861
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	26,538,502	27,314,195
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	242,962	280,251
98	RentsTransmissionElectricExpense (567) Rents	1,101,354	1,051,313
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	36,914,359	37,533,121
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	590,613	589,057
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	61,337	28,013
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	1,442,191	1,072,036
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	2,873	2,787
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment		107,053
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	747,867	772,362
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	3,602,567	4,160,440
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	370	201
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	6,447,818	6,731,949
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	43,362,177	44,265,070
113	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
114	RegionalMarketExpensesOperationAbstract Operation
115	OperationSupervision (575.1) Operation Supervision
116	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation	326,294	403,856
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation	93,227	115,386
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance	46,614	57,694
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	466,135	576,936
124	RegionalMarketExpensesMaintenanceAbstract Maintenance
125	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
126	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
127	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
128	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
129	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
130	RegionalMarketMaintenanceExpense Total Maintenance (Lines 125 thru 129)
131	RegionalMarketExpenses TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)	466,135	576,936
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	3,603,183	3,368,549
135	LoadDispatching (581) Load Dispatching
136	StationExpensesDistribution (582) Station Expenses	1,518,190	1,612,335
137	OverheadLineExpenses (583) Overhead Line Expenses	2,133,592	1,933,123
138	UndergroundLineExpenses (584) Underground Line Expenses	2,859,334	2,886,644
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	163,058	189,357
140	MeterExpenses (586) Meter Expenses	2,369,994	2,543,121
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	1,927,758	1,627,282
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	3,145,062	2,946,278
143	RentsDistributionExpense (589) Rents	81,786	79,059
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	17,801,957	17,185,748
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	1,647,819	1,377,391
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	28,996	35,634
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	652,201	721,567
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	14,913,075	13,347,613
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,493,511	1,082,933
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	47,628	118,023
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	616,173	635,363
153	MaintenanceOfMeters (597) Maintenance of Meters	1,694,997	1,547,625
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	43,662	44,445
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	21,138,062	18,910,594
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	38,940,019	36,096,342
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision
160	MeterReadingExpenses (902) Meter Reading Expenses	1,313,720	1,600,412
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	7,782,099	7,599,922
162	UncollectibleAccounts (904) Uncollectible Accounts	1,656,016	160,180
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	47,387	87,471
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	10,799,222	9,447,985
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	3,459,332	3,452,008
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	1,123,871	1,169,120
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	79,969	625,631
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	4,663,172	5,246,759
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses
176	AdvertisingExpenses (913) Advertising Expenses	1,119,259	354,190
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	1,119,259	354,190
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	31,673,768	32,114,942
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	14,842,877	11,591,266
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	7,811,070	7,333,865
184	OutsideServicesEmployed (923) Outside Services Employed	8,190,730	9,575,955
185	PropertyInsurance (924) Property Insurance	3,045,613	3,097,423
186	InjuriesAndDamages (925) Injuries and Damages	10,883,643	9,118,837
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	(d) 22,191,172	30,464,999
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	3,240,980	2,627,288
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	327,308	26,062
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	(e) 14,579,531	13,568,468
193	RentsAdministrativeAndGeneralExpense (931) Rents	1,095,678	1,489,592
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	102,260,230	106,340,967
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	4,495,653	2,104,958
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	106,755,883	108,445,925
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	594,798,983	532,482,319

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: OperationSupervisionAndEngineeringSteamPowerGeneration


		MONTANA OPERATIONS
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (b)
1	1. POWER PRODUCTION EXPENSES
2	A. Steam Power Generation
3	Operation
4	500 Operation supervision and engineering	51,013	29,749
5	501 Fuel	34,302,960	28,328,968
6	502 Steam expenses	1,438,025	1,782,038
7	503 Steam from other sources		—
8	504 Less: Steam transferred-Cr		—
9	505 Electric expenses	536,048	197,583
10	506 Miscellaneous steam power expenses	2,379,298	2,153,527
11	507 Rents	—	—
12	509 Allowances		—
13	Total Operation	38,707,344	32,491,865
14	Maintenance
15	510 Maintenance supervision and engineering	521,165	597,546
16	511 Maintenance of structures	727,635	635,316
17	512 Maintenance of boiler plant	4,289,231	5,872,037
18	513 Maintenance of electric plant	685,935	1,408,466
19	514 Maintenance of miscellaneous steam plant	398,284	399,293
20	Total maintenance	6,622,250	8,912,658
21	Total Power Production Expenses-Steam Power	45,329,594	41,404,523
22	B. Nuclear Power Generation
23	Operation
24	517 Operation supervision and engineering
25	518 Fuel
26	519 Coolants and water
27	520 Steam expenses
28	521 Steam from other sources
29	522 Less: Steam transferred-Cr
30	523 Electric expenses
31	524 Miscellaneous nuclear power expenses
32	525 Rents
33	Total Operation	—	—
34	Maintenance
35	528 Maintenance supervision and engineering
36	529 Maintenance of structures
37	530 Maintenance of Reactor Plant Equipment
38	531 Maintenance of electric plant
39	532 Maintenance of miscellaneous nuclear plant
40	Total maintenance	—	—
41	Total Power Production Expenses-Nuc. Power	—	—
42	C. Hydraulic Power Generation
43	Operation
44	535 Operation supervision and engineering	678,516	613,183
45	536 Water for power	949,611	942,963
46	537 Hydraulic expenses	3,654,685	3,804,078
47	538 Electric expenses	3,662,440	3,315,093
48	539 Miscellaneous hydraulic power generation expenses	2,903,753	3,269,367


49	540 Rents	808,039	788,771
50	Total Operation	12,657,044	12,733,455
51	C. Hydraulic Power Generation (continued)
52	Hydraulic Power Generation - Maintenance
53	541 Maintenance supervision and engineering	560,468	517,919
54	542 Maintenance of structures	715,688	683,786
55	543 Maintenance of reservoirs, dams and waterways	612,490	758,707
56	544 Maintenance of electric plant	1,228,566	1,006,837
57	545 Maintenance of miscellaneous hydraulic plant	215,886	540,433
58	Total Maintenance	3,333,098	3,507,682
59	Total power production expenses-hydraulic power	15,990,142	16,241,137

60	D. Other Power Generation
61	Operation
62	546 Operation supervision and engineering	437,140	412,994
63	547 Fuel	26,489,691	17,702,343
64	548 Generation expenses	3,832,823	3,484,533
65	549 Miscellaneous other power generation expenses	1,812,546	764,012
66	550 Rents	—	—
67	Total Operation	32,572,200	22,363,882
68	Maintenance
69	551 Maintenance supervision and engineering	—	—
70	552 Maintenance of structures	1,130	921
71	553 Maintenance of generating and electric plant	1,678,576	1,447,583
72	554 Maintenance of miscellaneous other power generating plant	60,566	139,071
73	Total Maintenance	1,740,272	1,587,575
74	Total power production expenses-other power	34,312,472	23,951,457
75	E. Other Power Supply Expenses
76	555 Purchased power	270,689,407	225,096,748
77	556 System control and load dispatching	—	—
78	557 Other expenses	(47,735,181)	(37,816,439)
79	Total other power supply exp	222,954,226	187,280,309
80	Total power production expenses	318,586,434	268,877,426
81	2. Transmission Expenses
82	Operation
83	560 Operation supervision and engineering	2,464,420	2,536,070
84	561 Load dispatching	—	—
85	561.1 Load dispatch-reliability	936,249	815,676
86	561.2 Load dispatch-monitor and operate transmission ssystem	965,381	785,789
87	561.3 Load dispatch-transmission service and scheduling	1,354,193	1,210,918
88	561.4 Scheduling, system control and dispatch services		—
89	561.5 Reliability, planning and standards development	—	—
90	561.6 Transmission service studies		—
91	561.7 Generation interconnection studies		—
92	561.8 Reliability, planning and standards development services		—
93	562 Station expenses	1,285,180	1,418,394
94	563 Overhead line expenses	1,163,275	1,287,915
95	564 Underground line expenses		—
96	565 Transmission of electricity by others	6,570,785	7,252,597
97	566 Miscellaneous transmission expense	153,589	207,645
98	567 Rents	1,076,543	1,055,995
99	Total Operation	15,969,615	16,570,999
100	Maintenance
101	568 Maintenance supervision and engineering	517,276	527,566
102	569 Maintenance of structures	48,248	10,288


103	569.1 Maintenance of computer hardware	1,442,191	1,072,036
104	569.2 Maintenance of computer software	2,874	2,787
105	569.3 Maintenance of communication equipment	—	—
106	569.4 Maintenance of miscellaneous regional transmission plant		—
107	570 Maintenance of station equipment	662,815	676,061
108	571 Maintenance of overhead lines	3,278,719	3,957,825
109	572 Maintenance of underground lines	—	—
110	573 Maintenance of miscellaneous transmission plant		—
111	Total Maintenance	5,952,123	6,246,563
112	Total transmission expenses	21,921,738	22,817,562

113	3. Regional Market Expenses
114	Operation
115	575.1 Operation supervision
116	575.2 Day-ahead and real-time market facilitation
117	575.3 Transmission rights market facilitation
118	575.4 Capacity market facilitation
119	575.5 Ancillary services market facilitation
120	575.6 Market monitoring and compliance
121	575.7 Market facilitation, monitoring and compliance services
122	575.8 Rents
123	Total Operation	—	—
124	Maintenance
125	576.1 Maintenance of structures and improvements
126	576.2 Maintenance of computer hardware
127	576.3 Maintenance of computer software
128	576.4 Maintenance of communication equipment
129	576.5 Maintenance of miscellaneous market operation plant
130	Total Maintenance	—	—
131	Total Regional Transmission and Market Op. Expns.	—	—
132	4. Distribution Expenses
133	Operation
134	580 Operations supervision and engineering	3,145,756	2,859,373
135	581 Load dispatching
136	582 Station expenses	1,284,768	1,417,734
137	583 Overhead line expenses	1,759,824	1,478,337
138	584 Underground line expenses	2,194,129	2,142,808
139	585 Street lighting and signal system expenses	113,330	124,938
140	586 Meter expenses	1,907,076	2,070,041
141	587 Customer installation expenses	1,720,348	1,396,370
142	588 Miscellaneous distribution expenses	2,510,632	2,306,890
143	589 Rents	81,788	79,059
144	Total Operation	14,717,651	13,875,550
145	Maintenance
146	590 Maintenance supervision and engineering	1,443,455	1,189,345
147	591 Maintenance of structures	28,996	35,634
148	592 Maintenance of station equipment	460,939	580,063
149	593 Maintenance of overhead lines	13,206,141	11,870,107
150	594 Maintenance of underground lines	1,348,635	941,998
151	595 Maintenance of line transformers	47,053	111,926
152	596 Maintenance of street lighting and signal systems	365,502	358,966
153	597 Maintenance of meters	1,317,093	1,374,039
154	598 Maintenance of miscellaneous distribution plant	—	—
155	Total Maintenance	18,217,814	16,462,078
156	Total distribution expenses	32,935,465	30,337,628


157	5. Customer Accounts Expenses
158	Operation
159	901 Supervision
160	902 Meter reading expenses	1,266,522	1,538,786
161	903 Customer records and collection expenses	6,705,862	6,376,777
162	904 Uncollectible accounts	1,300,105	(205,302)
163	905 Miscellaneous customer accounts expenses	(21)	35,261
164	Total customer accounts expenses	9,272,468	7,745,522

165	Customer Service and Informational Expenses
166	Operation
167	907 Supervision
168	908 Customer assistance expenses	2,451,956	2,416,841
169	909 Informational and instructional advertising expenses	978,485	1,053,901
170	910 Miscellaneous customer service and informational expenses	—	561,511
171	Total customer service and informational expenses	3,430,441	4,032,253
172	7. Sales Expenses
173	Operation
174	911 Supervision
175	912 Demonstrating and selling expenses
176	913 Advertising expenses	1,052,442	327,676
177	916 Miscellaneous sales expenses
178	Total sales expenses	1,052,442	327,676
179	8. Administrative and General Expenses
180	Operation
181	920 Administrative and general salaries	27,735,564	27,967,490
182	921 Office supplies and expenses	12,613,500	9,478,103
183	922 Less: Administrative expenses transferred - credits	6,531,731	6,194,522
184	923 Outside services employed	7,386,228	8,654,561
185	924 Property insurance	2,878,745	2,361,896
186	925 Injuries and damages	9,228,383	7,983,990
187	926 Employee pensions and benefits	19,197,833	28,051,481
188	927 Franchise requirements		—
189	928 Regulatory commission expenses	3,238,766	2,625,393
190	929 Less: Duplicate charges - credit		—
191	930.1 General advertising expenses	233,499	9,677
192	930.2 Miscellaneous general expenses	13,993,910	12,910,309
193	931 Rents	915,820	1,191,702
194	Total Operations	90,890,517	95,040,080
195	Maintenance
196	935 Maintenance of general plant	3,883,834	1,885,403
197	Total administrative and general expenses	94,774,351	96,925,483
198	Total Elec. Op. and Maint. Expns.	481,973,337	431,063,550

(b) Concept: FuelSteamPowerGeneration


		SOUTH DAKOTA OPERATIONS
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (b)
1	1. POWER PRODUCTION EXPENSES
2	A. Steam Power Generation
3	Operation
4	500 Operation supervision and engineering	735,685	806,576
5	501 Fuel	19,814,101	16,017,055
6	502 Steam expenses	1,299,624	1,733,967
7	503 Steam from other sources
8	504 Less: Steam transferred-Cr
9	505 Electric expenses	677,406	605,247
10	506 Miscellaneous steam power expenses	1,201,776	1,317,257
11	507 Rents	29,366	33,465
12	509 Allowances
13	Total Operation	23,757,958	20,513,567
14	Maintenance
15	510 Maintenance supervision and engineering	607,635	657,661
16	511 Maintenance of structures	340,835	371,582
17	512 Maintenance of boiler plant	2,528,659	3,563,491
18	513 Maintenance of electric plant	1,323,412	876,875
19	514 Maintenance of miscellaneous steam plant	573,086	472,199
20	Total maintenance	5,373,627	5,941,808
21	Total Power Production Expenses-Steam Power	29,131,585	26,455,375
22	B. Nuclear Power Generation
23	Operation
24	517 Operation supervision and engineering
25	518 Fuel
26	519 Coolants and water
27	520 Steam expenses
28	521 Steam from other sources
29	522 Less: Steam transferred-Cr
30	523 Electric expenses
31	524 Miscellaneous nuclear power expenses
32	525 Rents
33	Total Operation	—	—
34	Maintenance
35	528 Maintenance supervision and engineering
36	529 Maintenance of structures
37	530 Maintenance of Reactor Plant Equipment
38	531 Maintenance of electric plant
39	532 Maintenance of miscellaneous nuclear plant
40	Total maintenance	—	—
41	Total Power Production Expenses-Nuc. Power	—	—
42	C. Hydraulic Power Generation
43	Operation
44	535 Operation supervision and engineering
45	536 Water for power
46	537 Hydraulic expenses
47	538 Electric expenses
48	539 Miscellaneous hydraulic power generation expenses
49	540 Rents
50	Total Operation	—	—


51	C. Hydraulic Power Generation (continued)
52	Hydraulic Power Generation - Maintenance
53	541 Maintenance supervision and engineering
54	542 Maintenance of structures
55	543 Maintenance of reservoirs, dams and waterways
56	544 Maintenance of electric plant
57	545 Maintenance of miscellaneous hydraulic plant
58	Total Maintenance	—	—
59	Total power production expenses-hydraulic power	—	—

60	D. Other Power Generation
61	Operation
62	546 Operation supervision and engineering	285,048	244,941
63	547 Fuel	7,234,698	5,775,654
64	548 Generation expenses	4,192,889	3,971,695
65	549 Miscellaneous other power generation expenses	593,589	466,934
66	550 Rents	—	—
67	Total Operation	12,306,224	10,459,224
68	Maintenance
69	551 Maintenance supervision and engineering	50,511	26,695
70	552 Maintenance of structures	156,974	63,642
71	553 Maintenance of generating and electric plant	763,021	591,518
72	554 Maintenance of miscellaneous other power generating plant	14,978	10,277
73	Total Maintenance	985,484	692,132
74	Total power production expenses-other power	13,291,708	11,151,356
75	E. Other Power Supply Expenses
76	555 Purchased power	18,710,205	32,543,744
77	556 System control and load dispatching	304,468	280,190
78	557 Other expenses	8,668,714	(11,258,979)
79	Total other power supply exp	27,683,387	21,564,955
80	Total power production expenses	70,106,681	59,171,686
81	2. Transmission Expenses
82	Operation
83	560 Operation supervision and engineering	175,189	259,011
84	561 Load dispatching	63,839	63,158
85	561.1 Load dispatch-reliability	—	—
86	561.2 Load dispatch-monitor and operate transmission ssystem	—	101,269
87	561.3 Load dispatch-transmission service and scheduling	3,000	3,000
88	561.4 Scheduling, system control and dispatch services
89	561.5 Reliability, planning and standards development	94,637	88,280
90	561.6 Transmission service studies
91	561.7 Generation interconnection studies
92	561.8 Reliability, planning and standards development services
93	562 Station expenses	329,647	122,936
94	563 Overhead line expenses	196,531	194,946
95	564 Underground line expenses
96	565 Transmission of electricity by others	19,967,717	20,061,598
97	566 Miscellaneous transmission expense	89,373	72,606
98	567 Rents	24,811	(4,682)
99	Total Operation	20,944,744	20,962,122
100	Maintenance
101	568 Maintenance supervision and engineering	73,337	61,491
102	569 Maintenance of structures	13,089	17,725
103	569.1 Maintenance of computer hardware	—	—
104	569.2 Maintenance of computer software	—	—


105	569.3 Maintenance of communication equipment	—	107,053
106	569.4 Maintenance of miscellaneous regional transmission plant
107	570 Maintenance of station equipment	85,051	96,301
108	571 Maintenance of overhead lines	323,848	202,615
109	572 Maintenance of underground lines	370	201
110	573 Maintenance of miscellaneous transmission plant
111	Total Maintenance	495,695	485,386
112	Total transmission expenses	21,440,439	21,447,508

113	3. Regional Market Expenses
114	Operation
115	575.1 Operation supervision
116	575.2 Day-ahead and real-time market facilitation	326,293	403,856
117	575.3 Transmission rights market facilitation
118	575.4 Capacity market facilitation
119	575.5 Ancillary services market facilitation	93,227	115,386
120	575.6 Market monitoring and compliance	46,613	57,694
121	575.7 Market facilitation, monitoring and compliance services
122	575.8 Rents
123	Total Operation	466,133	576,936
124	Maintenance
125	576.1 Maintenance of structures and improvements
126	576.2 Maintenance of computer hardware
127	576.3 Maintenance of computer software
128	576.4 Maintenance of communication equipment
129	576.5 Maintenance of miscellaneous market operation plant
130	Total Maintenance	—	—
131	Total Regional Transmission and Market Op. Expns.	+	+
132	4. Distribution Expenses
133	Operation
134	580 Operations supervision and engineering	457,427	509,176
135	581 Load dispatching
136	582 Station expenses	233,422	194,601
137	583 Overhead line expenses	373,768	454,786
138	584 Underground line expenses	665,205	743,836
139	585 Street lighting and signal system expenses	49,729	64,419
140	586 Meter expenses	462,917	473,080
141	587 Customer installation expenses	207,410	230,912
142	588 Miscellaneous distribution expenses	634,430	639,388
143	589 Rents	—	—
144	Total Operation	3,084,308	3,310,198
145	Maintenance
146	590 Maintenance supervision and engineering	204,364	188,046
147	591 Maintenance of structures
148	592 Maintenance of station equipment	191,261	141,504
149	593 Maintenance of overhead lines	1,706,934	1,477,506
150	594 Maintenance of underground lines	144,876	140,935
151	595 Maintenance of line transformers	575	6,097
152	596 Maintenance of street lighting and signal systems	250,671	276,397
153	597 Maintenance of meters	377,904	173,586
154	598 Maintenance of miscellaneous distribution plant	43,662	44,445
155	Total Maintenance	2,920,247	2,448,516
156	Total distribution expenses	6,004,555	5,758,714
157	5. Customer Accounts Expenses
158	Operation


159	901 Supervision
160	902 Meter reading expenses	47,199	61,626
161	903 Customer records and collection expenses	1,076,237	1,223,145
162	904 Uncollectible accounts	355,912	365,482
163	905 Miscellaneous customer accounts expenses	47,408	52,210
164	Total customer accounts expenses	1,526,756	1,702,463

165	Customer Service and Informational Expenses
166	Operation
167	907 Supervision
168	908 Customer assistance expenses	1,007,375	1,035,167
169	909 Informational and instructional advertising expenses	145,386	115,219
170	910 Miscellaneous customer service and informational expenses	79,970	64,120
171	Total customer service and informational expenses	1,232,731	1,214,506
172	7. Sales Expenses
173	Operation
174	911 Supervision
175	912 Demonstrating and selling expenses
176	913 Advertising expenses	66,816	26,514
177	916 Miscellaneous sales expenses
178	Total sales expenses	66,816	26,514
179	8. Administrative and General Expenses
180	Operation
181	920 Administrative and general salaries	3,938,203	4,147,452
182	921 Office supplies and expenses	2,229,377	2,113,163
183	922 Less: Administrative expenses transferred - credits	1,279,340	1,139,343
184	923 Outside services employed	804,502	921,394
185	924 Property insurance	166,868	735,527
186	925 Injuries and damages	1,655,258	1,134,847
187	926 Employee pensions and benefits	2,993,341	2,413,518
188	927 Franchise requirements
189	928 Regulatory commission expenses	2,213	1,895
190	929 Less: Duplicate charges - credit
191	930.1 General advertising expenses	93,810	16,385
192	930.2 Miscellaneous general expenses	585,621	658,159
193	931 Rents	179,857	297,890
194	Total Operations	11,369,710	11,300,887
195	Maintenance
196	935 Maintenance of general plant	611,823	219,555
197	Total administrative and general expenses	11,981,533	11,520,442
198	Total Elec. Op. and Maint. Expns.	112,825,646	101,418,769


Account 557 Other Expenses			Amount

Account 557 Total Expense			(47,200,181)

Less: Variable Supply Costs			(48,694,267)

Amount to disclose in FERC Template page WP_FCR			1,494,086

Account 557 Fixed costs:
Wind Procurement Costs			143,922
OATI-Default Electric Supply			—
Schedulers-Default Electric			—
Res Acq EL-Supply Operations			967,983
Mktg Sup EL-Supply Operation			180,154
Gen Adm Oth Power Sup			75,862
Eng Sup Plan-Other Power Sup			49,017
Mktg Supply-Other Power Supp			77,148
Subtotal			1,494,086

(d) Concept: EmployeePensionsAndBenefits


Plan Name	MT Medical (Regulatory)
Country	US
Fiscal year ending on	Dec 31, 2022
A. Net Periodic Benefit Cost
1. Service cost	$	307,609
2. Interest cost	313,259
3. Expected return on plan assets	(1,046,911)
4. Amortization of initial net obligation (asset)	—
5. Amortization of prior service cost	(1,798,052)
6. Amortization of net (gain) loss	104,068
7. Curtailment (gain)/loss recognized	—
8. Settlement (gain)/loss recognized	—
9. Special termination benefit recognized	—
10. Net periodic benefit cost	$	(2,120,027)

Electric Only	(1,070,677)

(e) Concept: MiscellaneousGeneralExpenses


	Montana Operations	South Dakota Operations	Total 930.2
Universal System Benefits Charge	10,465,306	—	10,465,306
Our Portion of Shared Ownership Gen	1,188,193	—	1,188,193
	11,653,499	—	11,653,499

Board of Directors Fees	1,603,519	262,872	1,866,391
Shareholder Expense	195,533	32,055	227,588
Industry & Association Dues	374,103	260,930	635,033
Amortization of upfront fees	112,595	18,458	131,053
Human Resources general expenses (non-labor and not provided for elsewhere)	26,444	4,929	31,373
Miscellaneous	28,217	6,377	34,594
	2,340,411	585,621	2,926,032

Total Account 930.2	13,993,910	585,621	14,579,531

Montana Operations Miscellaneous General Expenses account 930.2 includes $78,927 of Electric non-allowed Industry and Association Dues, which is removed for rate making purposes.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 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). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	MONTANA PURCHASES
2	QUALIFYING FACILITIES
3	TIER II QF CONTRACTS:
4	Billings Generation Inc (TIER II QF)	LU					459,076					46,916,123	(a) 9,705	46,906,418
5	Colstrip Energy Ltd/Montana One (TIER II QF)	LU					291,746					22,672,063	(b) 469,149	23,141,212
6	Hydrodynamics - Strawberry Creek (TIER II QF)	LU					1,220					77,958	(c) 235	77,723
7	Pine Creek (TIER II QF)	LU					1,225					98,896	(d) 6,087	92,809
8	Ross Creek Hydro (TIER II QF)	LU					1,617					61,885	(e) 2,840	59,045
9	State of Montana-DNRC / Broadwater Dam (TIER II QF)	LU					39,303					5,209,743	(f) 5,088	5,204,655
10	NON TIER II QF-1 CONTRACTS
11	71 Ranch (NON TIER II QF-1)	LU					11,850					655,915		655,915
12	Barney Creek (NON TIER II QF-1)	LU					1					37		37
13	Big Timber Wind (NON TIER II QF-1)	LU					89,488					4,060,557		4,060,557
14	Boulder Hydro (NON TIER II QF-1)	LU					993					66,322		66,322
15	Broadview East/Two Dot (NON TIER II QF-1)	LU					5,043					257,530		257,530
16	Cascade Creek (NON TIER II QF-1)	LU					4					273		273
17	Cycle Horseshoe Bend (NON TIER II QF-1)	LU					5,778					214,458		214,458
18	DA Wind (NON TIER II QF-1)	LU					11,551					638,121		638,121
19	Fairfield Wind (NON TIER II QF-1)	LU					36,755					2,022,737	(g) 105,655	1,917,082
20	Flint Creek Hydro (NON TIER II QF-1)	LU					8,783					623,035		623,035
21	Gordon Butte Wind (NON TIER II QF-1)	LU					40,520					2,804,403		2,804,403
22	Greenfield (NON TIER II QF-1)	LU					92,243					4,623,043		4,623,043
23	Hanover Hydro (NON TIER II QF-1)	LU					275					17,167		17,167
24	Lower South Fork (NON TIER II QF-1)	LU					54					2,910		2,910
25	Musselshell Wind 1 (NON TIER II QF-1)	LU					28,790					1,992,559		1,992,559
26	Musselshell Wind 2 (NON TIER II QF-1)	LU					33,671					2,330,343		2,330,343
27	Oversight Resources (NON TIER II QF-1)	LU					10,985					606,949		606,949
28	Pony Hydro (NON TIER II QF-1)	LU					672					27,482		27,482
29	South Dry Creek (NON TIER II QF-1)	LU					365					2,842		2,842
30	South Peak Wind (NON TIER II QF-1)	LU					308,859					6,924,484		6,924,484
31	Stillwater Wind (NON TIER II QF-1)	LU					301,650					11,340,812		11,340,812
32	Wisconsin Creek (NON TIER II QF-1)	LU					600					21,480		21,480
33	KEC Fighting Creek (NON TIER II QF-1)	LU					1,855					122,705		122,705
34	NON TIER II SOLAR QF CONTRACTS
35	River Bend Solar (NON TIER II SOLAR QF)	LU					3,531					226,722		226,722
36	Green Meadow Solar (NON TIER II SOLAR QF)	LU					5,556					364,850		364,850
37	South Mills Solar 1 (NON TIER II SOLAR QF)	LU					5,886					380,549		380,549
38	Black Eagle Solar (NON TIER II SOLAR QF)	LU					5,328					351,472		351,472
39	Great Divide Solar LLC (NON TIER II SOLAR QF)	LU					6,056					396,585		396,585
40	Magpie Solar LLC (NON TIER II SOLAR QF)	LU					5,483					357,158		357,158
41	Montana Sun, LLC (NON TIER II SOLAR QF)	LU					2,612					50,049		50,049
42	RESERVE SHARING TRANSACTIONS:
43	AVISTA CORPORATION (RESERVE SHARING)	LF	Reserve Energy Services				23					1,625		1,625
44	AVANGRID RENEWABLES, LLC (RESERVE SHARING)	LF	Reserve Energy Services				30					2,242		2,242
45	BONNEVILLE POWER ADMINISTRATION (RESERVE SHARING)	LF	Reserve Energy Services				380					30,299		30,299
46	CHELAN COUNT PUD (RESERVE SHARING)	LF	Reserve Energy Services				20					1,720		1,720
47	GRIDFORCE ENERGY MANAGEMENT (RESERVE SHARING)	LF	Reserve Energy Services				36					3,182		3,182
48	DOUGLAS COUNTY PUD (RESERVE SHARING)	LF	Reserve Energy Services				12					1,073		1,073
49	GRANT COUNTY PUD (RESERVE SHARING)	LF	Reserve Energy Services				39					3,317		3,317
50	NATURENER GLACIER WIND ENERGY (RESERVE SHARING)	LF	Reserve Energy Services				5					464		464
51	NATURENER WIND WATCH (RESERVE SHARING)	LF	Reserve Energy Services				6					549		549
52	PACIFICORP (RESERVE SHARING)	LF	Reserve Energy Services				112					9,326		9,326
53	PORTLAND GENERAL ELECTRIC COMPANY (RESERVE SHARING)	LF	Reserve Energy Services				40					2,902		2,902
54	PUGET SOUND ENERGY (RESERVE SHARING)	LF	Reserve Energy Services				41					3,657		3,657
55	SEATTLE CITY LIGHT (RESERVE SHARING)	LF	Reserve Energy Services				53					4,502		4,502
56	TACOMA POWER (RESERVE SHARING)	LF	Reserve Energy Services				25					2,077		2,077
57	WESTERN AREA POWER ADMINISTATION (RESERVE SHARING)	LF	Reserve Energy Services				7					616		616
58	EXCHANGES:
59	Pacificorp - Costrip Loss/Startup (EXCHANGES)	EX	RS 190						2,277	2,281		1,790		1,790
60	Talen Energy Marketing, LLC - Startup (EXCHANGES)	EX	RS 190						3,443	3,420		3,202		3,202
61	Portland General Electric - Colstrip Loss/Startup (EXCHANGES)	EX	RS 190						4,513	4,528		1,146		1,146
62	Puget Sound Energy - Colstrip Units 3&4 Startup (EXCHANGES)	EX	RS 190						5,695	5,702		650		650
63	Northwestern Energy Colstrip Unit 4 - Startup (EXCHANGES)	EX	RS 190						3,416	3,421		294		294
64	AVISTA Corporation - Colstrip Loss/Startup (EXCHANGES)	EX	RS 190						3,434	3,421		1,473		1,473
65	PURCHASED POWER SUPPLY:
66	Avista Corporation (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				24,310					2,023,462		2,023,462
67	Basin Electric Power Cooperative (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				19,893					1,503,195		1,503,195
68	Basin Power Plant (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				78,619					6,433,897		6,433,897
69	Black Hills Power Inc (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				0
70	Bonneville Power Administration (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				39,042					3,190,317		3,190,317
71	Clatskanie Peoples Utility District - Electric (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				1,765					128,463		128,463
72	Conoco Phillips Corp (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				12,414					864,323		864,323
73	Shell Energy North America (US), L.P. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				8,878					432,423		432,423
74	Exelon Generation Company, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				1,746					88,221		88,221
75	EDF Trading North America, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				33,734					2,245,493		2,245,493
76	Energy Keepers, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				88,401					6,955,597		6,955,597
77	Eugene Water & Electric Board (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				3,221					197,709		197,709
78	Avangrid Renewables, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				15,724					930,041		930,041
79	Idaho Power Company (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				2,306					157,300		157,300
80	Invenergy Energy Marketing LLC-Electric (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				505,944					16,899,634		16,899,634
81	Macquarie Energy LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				62,939					5,653,795		5,653,795
82	Morgan Stanley Capital Group, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				468,051					40,694,319		40,694,319
83	PacifiCorp (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				1,441					90,965		90,965
84	Portland General Electric (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				159,602					20,414,180		20,414,180
85	Powerex Corp. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				23,084					8,018,895		8,018,895
86	Talen Energy Marketing, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				0
87	Puget Sound Energy (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				30,485					1,757,014		1,757,014
88	Rainbow Energy Marketing Corporation (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				9,938					1,000,405		1,000,405
89	Seattle City Light (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				12,705					924,090		924,090
90	Tacoma Power (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				6,115					510,375		510,375
91	The Energy Authority, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				75,537					5,376,007		5,376,007
92	Tiber Montana, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				45,947					1,986,898		1,986,898
93	TransAlta Energy Marketing (US), Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				14,131					955,257		955,257
94	Turnbull Hydro, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				29,721					1,561,072		1,561,072
95	Western Area Power Administation (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				980					70,950		70,950
96	Guzman Energy, LLC (PURCHASED POWER SUPPLY)	LU	Market-Based Rate Tariff				15,449					1,227,097		1,227,097
97	Dynasty Power, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				5,345					455,033		455,033
98	Heartland Generation Ltd (PURCHASED POWER SUPPLY)	LU	Market-Based Rate Tariff				5,175					10,392,750		10,392,750
99	Tenaska Power (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				318					21,590		21,590
100	California Independent System Operator - EIM Transmission (PURCHASED POWER SUPPLY)	SF	CAISO									9,326,252		9,326,252
101	California Independent System Operator - EIM Supply (PURCHASED POWER SUPPLY)	SF	CAISO									20,693,875		20,693,875
102	Estimate Energy (PURCHASED POWER SUPPLY)						0					21,970,265		21,970,265
103	SOUTH DAKOTA PURCHASES
104	WAPA (Various) (SOUTH DAKOTA PURCHASES)	OS	29				0					128,308		128,308
105	Lincoln Energy Services (SOUTH DAKOTA PURCHASES)	OS	29								69,000			69,000
106	Southwest Power Pool (SOUTH DAKOTA PURCHASES)	OS	SPP RTO				219,173					5,377,239		5,377,239
107	Titan Wind (PPA Wind #1) (SOUTH DAKOTA PURCHASES)	LU					92,042					6,589,008		6,589,008
108	Oak Tree (PPA Wind #2) (SOUTH DAKOTA PURCHASES)	LU					78,998					4,048,576		4,048,576
109	Aurora Wind (SOUTH DAKOTA PURCHASES)	LU					88,761					2,397,348		2,397,348
110	Brule Wind (SOUTH DAKOTA PURCHASES)	LU					86,802					2,327,023		2,327,023
111	Codington Clark Electric (SOUTH DAKOTA PURCHASES)	OS										11,142		11,142
112	MidAmerican Energy (SOUTH DAKOTA PURCHASES)	OS										28,402		28,402
113	Greenlight (SOUTH DAKOTA PURCHASES)	OS											(h) 1,563,917	1,563,917
114	MRES (SOUTH DAKOTA PURCHASES)	OS											(i) 701,924	701,924
115	Rounding						2					1		1
15	TOTAL						4,188,987	0	22,778	22,773	69,000	291,256,913	1,926,301	289,399,612

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment.

(b) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment.

(d) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment.

(e) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment.

(f) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment.

(g) Concept: OtherChargesOfPurchasedPower

Liquidated damages

(h) Concept: OtherChargesOfPurchasedPower

REC credit sales

(i) Concept: OtherChargesOfPurchasedPower

REC credit sales

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c). In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. Report in column (i) and (j) the total megawatthours received and delivered. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. Footnote entries and provide explanations following all required data.
									TRANSFER OF ENERGY		REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.	PaymentByCompanyOrPublicAuthority Payment By (Company of Public Authority) (Footnote Affiliation) (a)	TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName Energy Received From (Company of Public Authority) (Footnote Affiliation) (b)	TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c)	StatisticalClassificationCode Statistical Classification (d)	RateScheduleTariffNumber Ferc Rate Schedule of Tariff Number (e)	TransmissionPointOfReceipt Point of Receipt (Substation or Other Designation) (f)	TransmissionPointOfDelivery Point of Delivery (Substation or Other Designation) (g)	BillingDemand Billing Demand (MW) (h)	TransmissionOfElectricityForOthersEnergyReceived Megawatt Hours Received (i)	TransmissionOfElectricityForOthersEnergyDelivered Megawatt Hours Delivered (j)	Demand Charges ($) (k)	Energy Charges ($) (l)	Other Charges ($) (m)	RevenuesFromTransmissionOfElectricityForOthers Total Revenues ($) (k+l+m) (n)
1	MONTANA CHOICE TRANSMISSION
2	Ash Grove Cement	Energy Keepers Inc.	Ash Grove Cement	FNO	Montana OATT	Kerr	Clancy, MT	7	39,769	39,769	230,841			230,841
3	Aspen Air U.S., LLC	Talen Energy	Aspen Air Corporation	FNO	Montana OATT	Colstrip	Billings, MT	11	56,369	56,369	270,790			270,790
4	Barretts Minerals, Inc.	Energy Keepers inc.	Barretts Minerals, Inc.	FNO	Montana OATT	Kerr	Dillon, MT	6	30,872	30,872	177,716			177,716
5	Beartooth Electric Cooperative, Inc.	WAPA & Energy Keepers Inc.	Beartooth Electric Cooperative, Inc.	FNO	Montana OATT	Fort Peck & Kerr	Various in Montana	18	86,763	86,763	638,898			638,898
6	Benefis Health Systems	Energy Keepers inc.	Benefis Health Systems	FNO	Montana OATT	Kerr	Various in Montana	7	35,012	35,012	224,453			224,453
7	Big Horn County Electric Coop. Inc.	WAPA	Big Horn County Electric Coop. Inc.	FNO	Montana OATT	Various & Great Falls	Various in Montana	18	71,412	71,412	530,589			530,589
8	Bonneville Power Administration	BPA	Bonneville Power Administration	FNO	Montana OATT	BPAT.NWMT	Various in Montana	185	913,000	913,000	5,708,809			5,708,809
9	Basin Electric Power Cooperative	Morgan Stanley, Talen & WAPA	Basin Electric Power Cooperative	FNO	Montana OATT	Various in Montana	Various NWMT & WAUW	181	865,562	865,562	5,841,884			5,841,884
10	Basin Electric Power Cooperative	Basin Electric & WAPA	Basin Electric Power Cooperative	FNO	Montana OATT	Crossover	Various NWMT & WAUW	15	80,500	80,500	528,664			528,664
11	CHS, Inc.	Morgan Stanley	CHS, Inc.	FNO	Montana OATT	MATL.NWMT	Various in Montana	58	366,257	366,257	1,951,647			1,951,647
12	City of Great Falls	Energy Keepers Inc.	City of Great Falls	FNO	Montana OATT	Kerr	Various in Montana	6	20,135	20,135	118,005			118,005
13	Talen Montana, LLC	Avista Energy	Colstrip Steam Electric Station	FNO	Montana OATT	Colstrip	Nichols Pump Sub	10	32,992	32,992	177,479			177,479
14	Atlas Power, LLC	Portland General Electric	Atlas Power, LLC	FNO	Montana OATT	Colstrip	Butte, MT	75	348,026	348,026	1,125,199			1,125,199
15	Phillips 66 Company	Shell Energy	Phillips 66 Company	FNO	Montana OATT	BPAT.NWMT	Various in Montana	70	419,338	419,338	2,302,357			2,302,357
16	ExxonMobil Corporation	Talen Energy	ExxonMobil Corporation	FNO	Montana OATT	Colstrip	Billings, MT	35	227,302	227,302	1,244,394			1,244,394
17	General Mills Operations, LLC	Energy Keepers Inc.	General Mills Operations, LLC	FNO	Montana OATT	Kerr	Great Falls, MT	4	19,600	19,600	112,233			112,233
18	Great Falls Public Schools	Energy Keepers Inc.	Great Falls Public Schools	FNO	Montana OATT	Kerr	Great Falls, MT	3	9,588	9,588	64,050			64,050
19	GCC Three Forks, LLC	Energy Keepers Inc.	GCC Three Forks, LLC	FNO	Montana OATT	Kerr	Three Forks, MT	8	42,591	42,591	218,844			218,844
20	Magris Talc USA, Inc.	Energy Keepers Inc.	Magris Talc USA, Inc.	FNO	Montana OATT	Kerr	Three Forks, MT	6	28,923	28,923	175,675			175,675
21	DFA Dairy Brands Fluid, LLC	Talen Energy	Suiza Dairy Group, LLC	FNO	Montana OATT	Colstrip	Various in Montana	2	6,280	6,280	38,068			38,068
22	Calumet Refining, LLC	Talen Energy	Calumet Montana Refining Company, Inc.	FNO	Montana OATT	Colstrip	Great Falls, MT	25	91,750	91,750	572,724			572,724
23	Montana Resources	Talen Energy & Energy Keepers, Inc.	Montana Resources	FNO	Montana OATT	Colstrip & Kerr	Butte, MT	50	356,484	356,484	1,934,382			1,934,382
24	REC Silicon Company	Morgan Stanley	REC Silicon Company	FNO	Montana OATT	Hardin	Butte, MT	117	585,233	585,233	3,044,464			3,044,464
25	Roseburg Forest Products Company	Shell Energy	Roseburg Forest Products Company	FNO	Montana OATT	BPAT.NWMT	Missoula, MT	8	49,926	49,926	273,284			273,284
26	Sibanye-Stillwater	Energy Keepers Inc.	Stillwater Mining Company	FNO	Montana OATT	Kerr	Various in Montana	46	289,096	289,096	1,481,905			1,481,905
27	Town of Philipsburg	Town of Philipsburg	Town of Philipsburg	FNO	Montana OATT	Philipsburg Substation	Philipsburg, MT		662	662	4,359			4,359
28	Western Area Power Administration	WAPA	Western Area Power Administration	FNO	Montana OATT	Crossover	Various NWMT & WAUW	4	8	8	32,499			32,499
29	Montana State University - Bozeman	WAPA	Montana State University - Bozeman	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	16,060	16,060	89,187			89,187
30	Western Area Power Administration	WAPA	Malmstrom Air Force Base	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	27,611	27,611	158,344			158,344
31	MONTANA POINT-TO-POINT
32	Avista Corporation	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		22,161	22,161		105,666		105,666
33	Avista Corporation	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		96,340	96,340		497,400		497,400
34	Avista Corporation	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		800	800		3,774		3,774
35	Avista Corporation	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		265	265		1,227		1,227
36	Avista Corporation	NWMT	AVA	NF	MONTANA OATT	NWMTIMBALANC	AVAT.NWMT		150	150		820		820
37	Avista Corporation	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		288	288		1,333		1,333
38	Basin Electric Power Cooperative	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		723	723		3,347		3,347
39	Basin Electric Power Cooperative	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		202	202		935		935
40	Basin Electric Power Cooperative	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	GREATFALLS		625	625		2,894		2,894
41	Basin Electric Power Cooperative	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		401	401		2,358		2,358
42	Basin Electric Power Cooperative	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		10,292	10,292		47,672		47,672
43	Basin Electric Power Cooperative	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		40	40		185		185
44	Basin Electric Power Cooperative	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS		25	25		147		147
45	Basin Electric Power Cooperative	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	NWMT.SYSTEM		6	6		28		28
46	Basin Electric Power Cooperative	NWMT	PACE	NF	MONTANA OATT	BGI	YTP		288	288		1,693		1,693
47	Basin Electric Power Cooperative	NWMT	PACE	NF	MONTANA OATT	HOLTER	YTP		102	102		472		472
48	Basin Electric Power Cooperative	NWMT	PACE	NF	MONTANA OATT	JUDITHGAP	YTP		52	52		257		257
49	Basin Electric Power Cooperative	NWMT	PACE	NF	MONTANA OATT	STILLWIND	YTP		33	33		153		153
50	Basin Electric Power Cooperative	NWMT	PACE	NF	MONTANA OATT	CROOKEDFALLS	YTP		31	31		144		144
51	Basin Electric Power Cooperative	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		4,352	4,352		20,382		20,382
52	Basin Electric Power Cooperative	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		192	192		888		888
53	Basin Electric Power Cooperative	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER		28	28		130		130
54	Basin Electric Power Cooperative	NWMT	WAUW	NF	MONTANA OATT	COLSTRIP	GREATFALLS		14	14		65		65
55	Basin Electric Power Cooperative	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		450	450		2,084		2,084
56	Basin Electric Power Cooperative	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM		1,280	1,280		7,420		7,420
57	Basin Electric Power Cooperative	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM		618	618		3,104		3,104
58	Basin Electric Power Cooperative	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		1,056	1,056		6,204		6,204
59	Basin Electric Power Cooperative	PPW	PPW	NF	MONTANA OATT	BRDY	MLCK		830	830		3,843		3,843
60	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER		4,726	4,726		21,881		21,881
61	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	BRDY	GREATFALLS		541	541		2,923		2,923
62	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		23,685	23,685		120,717		120,717
63	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	YTP	GREATFALLS		943	943		5,294		5,294
64	Basin Electric Power Cooperative	WAPA	NWMT	NF	MONTANA OATT	CROSSOVER	NWMT.SYSTEM		151	151		850		850
65	Basin Electric Power Cooperative	WAPA	NWMT	SFP	MONTANA OATT	CROSSOVER	NWMT.SYSTEM		81,447	81,447		376,998		376,998
66	Basin Electric Power Cooperative	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		588	588		3,109		3,109
67	Basin Electric Power Cooperative	WAPA	WAPA	LFP	MONTANA OATT	CROSSOVER	GREATFALLS	31	271,560	271,560	1,391,812			1,391,812
68	Basin Electric Power Cooperative	WAPA	WAPA	NF	MONTANA OATT	CROSSOVER	GREATFALLS		95	95		440		440
69	Basin Electric Power Cooperative	WAUW	NWMT	SFP	MONTANA OATT	GREATFALLS	GTFALLSNWMT		480	480		2,220		2,220
70	Black Hills Power Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		95	95		465		465
71	Black Hills Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		75	75		441		441
72	Black Hills Power Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		1,050	1,050		5,174		5,174
73	Black Hills Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		154	154		906		906
74	Bonneville Power Administration	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM		67	67		310		310
75	Bonneville Power Administration	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		3,062	3,062		14,177		14,177
76	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		1,771	1,771		10,413		10,413
77	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		54	54		316		316
78	Bonneville Power Administration	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS		2,246	2,246		12,778		12,778
79	Bonneville Power Administration	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		230	230		1,065		1,065
80	Bonneville Power Administration	NWMT	BPAT	NF	MONTANA OATT	SOUTHPEAK	BPAT.NWMT		25	25		116		116
81	Bonneville Power Administration	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM		638	638		2,954		2,954
82	Brookfield Renewable Trading and Marketing LP	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		71	71		329		329
83	Brookfield Renewable Trading and Marketing LP	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		563	563		3,157		3,157
84	Brookfield Renewable Trading and Marketing LP	BPAT	WAPA	SFP	MONTANA OATT	BPAT.NWMT	CROSSOVER		8,400	8,400		49,300		49,300
85	Brookfield Renewable Trading and Marketing LP	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER		138	138		811		811
86	Brookfield Renewable Trading and Marketing LP	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		50	50		232		232
87	Brookfield Renewable Trading and Marketing LP	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		247	247		1,144		1,144
88	ConocoPhillips	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		200	200		926		926
89	ConocoPhillips	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		487	487		2,864		2,864
90	ConocoPhillips	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		1,722	1,722		7,973		7,973
91	CP Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		275	275		1,273		1,273
92	CP Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		9,014	9,014		41,735		41,735
93	CP Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP		29	29		134		134
94	CP Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		2,089	2,089		10,533		10,533
95	CP Energy Marketing (US) Inc.	PPW	PPW	NF	MONTANA OATT	YTP	JEFF		42	42		194		194
96	CP Energy Marketing (US) Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		684	684		3,192		3,192
97	CP Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF		2	2		9		9
98	CP Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		481	481		2,227		2,227
99	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	BRDY		4,305	4,305		22,657		22,657
100	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	JEFF		20,026	20,026		108,784		108,784
101	Dynasty Power Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY		275	275		1,617		1,617
102	Dynasty Power Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		905	905		4,253		4,253
103	Dynasty Power Inc.	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		904	904		4,186		4,186
104	Dynasty Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		1,131	1,131		6,642		6,642
105	Dynasty Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		46,032	46,032		216,518		216,518
106	Dynasty Power Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		4,119	4,119		21,926		21,926
107	Dynasty Power Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		2,121	2,121		9,820		9,820
108	Dynasty Power Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY		810	810		3,750		3,750
109	Dynasty Power Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		281	281		1,652		1,652
110	Dynasty Power Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		16,743	16,743		85,239		85,239
111	Dynasty Power Inc.	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		12,384	12,384		64,176		64,176
112	Dynasty Power Inc.	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		601	601		3,468		3,468
113	Dynasty Power Inc.	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER		92	92		541		541
114	Dynasty Power Inc.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		32	32		188		188
115	Dynasty Power Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		55,088	55,088		256,930		256,930
116	Dynasty Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		725	725		4,263		4,263
117	Dynasty Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		1,256	1,256		6,320		6,320
118	EDF Trading North America, LLC	AVA	AVA	NF	MONTANA OATT	AVAT.NWMT	AVAT.NWMT		20	20		93		93
119	EDF Trading North America, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		2,692	2,692		13,746		13,746
120	EDF Trading North America, LLC	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		2,975	2,975		13,875		13,875
121	EDF Trading North America, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	COLSTRIP		121	121		590		590
122	EDF Trading North America, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM		602	602		2,784		2,784
123	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP		1,967	1,967		9,747		9,747
124	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT		478	478		2,336		2,336
125	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		96	96		444		444
126	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		4,516	4,516		23,609		23,609
127	EDF Trading North America, LLC	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		1,437	1,437		6,653		6,653
128	EDF Trading North America, LLC	NWMT	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		27,480	27,480		124,295		124,295
129	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	CANYONFERRY	BPAT.NWMT		20	20		93		93
130	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		63,235	63,235		312,418		312,418
131	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		175	175		1,029		1,029
132	EDF Trading North America, LLC	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		28,128	28,128		140,142		140,142
133	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	BASINCREEK	NWMT.SYSTEM		110	110		509		509
134	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	BGI	COLSTRIP		8	8		47		47
135	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP		2,686	2,686		14,564		14,564
136	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT		228	228		1,278		1,278
137	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	NWMT.SYSTEM		48	48		222		222
138	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	HARDIN	NWMT.SYSTEM		10	10		46		46
139	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	JUDITHGAP	COLSTRIP		196	196		965		965
140	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	NWMTIMBALANC	NWMT.SYSTEM		30	30		139		139
141	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		1,298	1,298		7,520		7,520
142	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF		2	2		12		12
143	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		13,100	13,100		62,172		62,172
144	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	BRDY		8,400	8,400		49,350		49,350
145	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		4,320	4,320		22,980		22,980
146	EDF Trading North America, LLC	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER		46	46		239		239
147	EDF Trading North America, LLC	PACE	NWMT	NF	MONTANA OATT	YTP	COLSTRIP		177	177		941		941
148	EDF Trading North America, LLC	PPW	NWMT	NF	MONTANA OATT	YTP	GTFALLSNWMT		84	84		389		389
149	EDF Trading North America, LLC	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM		426	426		1,972		1,972
150	EDF Trading North America, LLC	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		696	696		4,089		4,089
151	Energy Keepers FIP	NWMT	BPAT	OLF	MONTANA OATT	KERR	BPAT.NWMT	8	69,984	69,984	176,771			176,771
152	Energy Keepers Inc.	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		1,472	1,472		6,815		6,815
153	Energy Keepers Inc.	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		696	696		3,219		3,219
154	Energy Keepers Inc.	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		16	16		74		74
155	Energy Keepers Inc.	AVA	BPAT	SFP	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		336	336		1,554		1,554
156	Energy Keepers Inc.	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	YTP		77,400	77,400		351,850		351,850
157	Energy Keepers Inc.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP		1,800	1,800		10,575		10,575
158	Energy Keepers Inc.	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT		1,257	1,257		5,995		5,995
159	Energy Keepers Inc.	NWMT	AVA	SFP	MONTANA OATT	KERR	AVAT.NWMT		312	312		1,443		1,443
160	Energy Keepers Inc.	NWMT	BPA	NF	MONTANA OATT	BGI	BPAT.NWMT		80	80		370		370
161	Energy Keepers Inc.	NWMT	BPAT	LFP	MONTANA OATT	KERR	BPAT.NWMT	40	350,400	350,400	1,795,887			1,795,887
162	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		640	640		2,963		2,963
163	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	HOLTER	BPAT.NWMT		40	40		185		185
164	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	JUDITHGAP	BPAT.NWMT		400	400		1,852		1,852
165	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT		1,930	1,930		9,668		9,668
166	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		50	50		232		232
167	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	STILLWIND	BPAT.NWMT		80	80		370		370
168	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	TFALLS	BPAT.NWMT		200	200		926		926
169	Energy Keepers Inc.	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		1,104	1,104		5,106		5,106
170	Energy Keepers Inc.	NWMT	BPAT	SFP	MONTANA OATT	KERR	BPAT.NWMT		31,755	31,755		151,947		151,947
171	Energy Keepers Inc.	NWMT	PACE	LFP	MONTANA OATT	KERR	BRDY	29	256,800	256,800	1,176,233			1,176,233
172	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	ANTE		25	25		116		116
173	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	BRDY		1,914	1,914		11,123		11,123
174	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	YTP		949	949		4,654		4,654
175	Energy Keepers Inc.	NWMT	PACE	SFP	MONTANA OATT	KERR	BRDY		55,031	55,031		322,179		322,179
176	Energy Keepers Inc.	NWMT	PACE	SFP	MONTANA OATT	KERR	JEFF		2,616	2,616		15,369		15,369
177	Energy Keepers Inc.	NWMT	PACE	SFP	MONTANA OATT	KERR	YTP		32,856	32,856		154,989		154,989
178	Energy Keepers Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		24	24		111		111
179	Energy Keepers Inc.	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		8,664	8,664		40,045		40,045
180	Energy Keepers Inc.	NWMT	WAUW	NF	MONTANA OATT	KERR	GREATFALLS		1	1		6		6
181	Energy Keepers Inc.	NWMT	WAUW	SFP	MONTANA OATT	MATL.NWMT	GREATFALLS		11,712	11,712		53,776		53,776
182	Energy Keepers Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		2,400	2,400		11,100		11,100
183	Energy Keepers Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		2,208	2,208		12,916		12,916
184	Energy Keepers Inc.	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		9,971	9,971		56,250		56,250
185	Energy Keepers Inc.	PPW	NWMT	SFP	MONTANA OATT	YTP	GTFALLSNWMT		24	24		111		111
186	Energy Keepers Inc.	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		996	996		5,856		5,856
187	Guzman Energy, LLC	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		25	25		147		147
188	Guzman Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY		1,092	1,092		5,640		5,640
189	Guzman Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		1,941	1,941		9,349		9,349
190	Guzman Energy, LLC	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	YTP		88,584	88,584		406,351		406,351
191	Guzman Energy, LLC	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		290	290		1,430		1,430
192	Guzman Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		1,338	1,338		7,774		7,774
193	Guzman Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		4,810	4,810		27,206		27,206
194	Guzman Energy, LLC	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP		58,704	58,704		272,661		272,661
195	Guzman Energy, LLC	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		17	17		79		79
196	Guzman Energy, LLC	NWMT	AVA	NF	MONTANA OATT	NWMTIMBALANC	AVAT.NWMT		4	4		24		24
197	Guzman Energy, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		270	270		1,588		1,588
198	Guzman Energy, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		390	390		2,262		2,262
199	Guzman Energy, LLC	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT		1,958	1,958		9,946		9,946
200	Guzman Energy, LLC	PPW	AVA	SFP	MONTANA OATT	BRDY	AVAT.NWMT		2,450	2,450		14,086		14,086
201	Guzman Energy, LLC	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		84,250	84,250		393,076		393,076
202	Guzman Energy, LLC	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		545	545		3,130		3,130
203	Guzman Energy, LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		16,439	16,439		90,414		90,414
204	Guzman Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	BRDY	BPAT.NWMT		1,104	1,104		6,486		6,486
205	Guzman Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		98,597	98,597		498,666		498,666
206	Guzman Energy, LLC	PPW	NWMT	NF	MONTANA OATT	YTP	GTFALLSNWMT		98	98		576		576
207	Guzman Energy, LLC	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM		16	16		94		94
208	Guzman Energy, LLC	PPW	PPW	NF	MONTANA OATT	BRDY	YTP		17	17		79		79
209	Guzman Energy, LLC	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		536	536		2,988		2,988
210	Guzman Energy, LLC	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT		66	66		306		306
211	Guzman Energy, LLC	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		2,263	2,263		10,478		10,478
212	Guzman Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		1,085	1,085		5,024		5,024
213	Iberdrola Renewables Inc.	NWMT	BPAT	NF	MONTANA OATT	SOUTHPEAK	BPAT.NWMT		30	30		139		139
214	Idaho Power Company	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	BRDY		12,000	12,000		70,500		70,500
215	Idaho Power Company	PPW	IPCO	NF	MONTANA OATT	JEFF	TNDY		91	91		421		421
216	Idaho Power Company	PPW	IPCO	SFP	MONTANA OATT	JEFF	TNDY		3,024	3,024		14,766		14,766
217	Macquarie Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY		36,000	36,000		166,300		166,300
218	Macquarie Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		7,592	7,592		35,115		35,115
219	Macquarie Energy, LLC	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	MLCK		192	192		888		888
220	Macquarie Energy, LLC	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	YTP		7,200	7,200		33,300		33,300
221	Macquarie Energy, LLC	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		14,645	14,645		67,688		67,688
222	Macquarie Energy, LLC	AVA	WAPA	SFP	MONTANA OATT	AVAT.NWMT	CROSSOVER		28,800	28,800		133,051		133,051
223	Macquarie Energy, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		600	600		2,778		2,778
224	Macquarie Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		1,600	1,600		9,408		9,408
225	Macquarie Energy, LLC	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		800	800		4,704		4,704
226	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	HOLTER	AVAT.NWMT		2,970	2,970		13,751		13,751
227	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	JUDITHGAP	AVAT.NWMT		1,500	1,500		6,939		6,939
228	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	TFALLS	AVAT.NWMT		4,158	4,158		19,252		19,252
229	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	MT1	AVAT.NWMT		330	330		1,527		1,527
230	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	CANYONFERRY	AVAT.NWMT		840	840		3,885		3,885
231	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	HOLTER	AVAT.NWMT		2,160	2,160		9,990		9,990
232	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	JUDITHGAP	AVAT.NWMT		1,200	1,200		5,550		5,550
233	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	TFALLS	AVAT.NWMT		2,640	2,640		12,210		12,210
234	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	MT1	AVAT.NWMT		1,560	1,560		7,215		7,215
235	Macquarie Energy, LLC	NWMT	BPA	NF	MONTANA OATT	BGI	BPAT.NWMT		480	480		2,822		2,822
236	Macquarie Energy, LLC	NWMT	BPA	SFP	MONTANA OATT	BGI	BPAT.NWMT		1,200	1,200		7,050		7,050
237	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	HOLTER	BPAT.NWMT		4,830	4,830		22,360		22,360
238	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	JUDITHGAP	BPAT.NWMT		274	274		1,467		1,467
239	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT		400	400		2,352		2,352
240	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	TFALLS	BPAT.NWMT		4,921	4,921		23,050		23,050
241	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	MT1	BPAT.NWMT		270	270		1,250		1,250
242	Macquarie Energy, LLC	NWMT	BPAT	SFP	MONTANA OATT	CANYONFERRY	BPAT.NWMT		1,200	1,200		5,550		5,550
243	Macquarie Energy, LLC	NWMT	BPAT	SFP	MONTANA OATT	HOLTER	BPAT.NWMT		1,200	1,200		5,550		5,550
244	Macquarie Energy, LLC	NWMT	BPAT	SFP	MONTANA OATT	TFALLS	BPAT.NWMT		1,800	1,800		9,075		9,075
245	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	HOLTER	BRDY		1,056	1,056		6,204		6,204
246	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	HOLTER	YTP		528	528		3,105		3,105
247	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	JUDITHGAP	BRDY		864	864		5,076		5,076
248	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	JUDITHGAP	YTP		72	72		423		423
249	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	KERR	BRDY		200	200		926		926
250	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	TFALLS	BRDY		880	880		5,172		5,172
251	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	TFALLS	YTP		965	965		5,468		5,468
252	Macquarie Energy, LLC	NWMT	PACE	SFP	MONTANA OATT	TFALLS	YTP		1,800	1,800		10,575		10,575
253	Macquarie Energy, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		2,248	2,248		10,397		10,397
254	Macquarie Energy, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		1,000	1,000		4,630		4,630
255	Macquarie Energy, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		16,800	16,800		77,600		77,600
256	Macquarie Energy, LLC	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER		3,530	3,530		16,326		16,326
257	Macquarie Energy, LLC	NWMT	WAPA	SFP	MONTANA OATT	COLSTRIP	CROSSOVER		9,984	9,984		54,276		54,276
258	Macquarie Energy, LLC	NWMT	WAUW	NF	MONTANA OATT	TFALLS	CROSSOVER		976	976		4,519		4,519
259	Macquarie Energy, LLC	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT		200	200		926		926
260	Macquarie Energy, LLC	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT		10,192	10,192		47,159		47,159
261	Macquarie Energy, LLC	PPW	AVA	SFP	MONTANA OATT	BRDY	AVAT.NWMT		5,640	5,640		31,125		31,125
262	Macquarie Energy, LLC	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		156,265	156,265		722,500		722,500
263	Macquarie Energy, LLC	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		1,560	1,560		9,165		9,165
264	Macquarie Energy, LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		5,806	5,806		27,348		27,348
265	Macquarie Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		81,575	81,575		376,650		376,650
266	Macquarie Energy, LLC	PPW	NWMT	SFP	MONTANA OATT	BRDY	NWMT.SYSTEM		1,200	1,200		7,050		7,050
267	Macquarie Energy, LLC	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		15,600	15,600		91,575		91,575
268	Macquarie Energy, LLC	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER		600	600		3,525		3,525
269	Macquarie Energy, LLC	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT		601	601		3,284		3,284
270	Macquarie Energy, LLC	WAPA	AVA	SFP	MONTANA OATT	CROSSOVER	AVAT.NWMT		2,040	2,040		9,435		9,435
271	Macquarie Energy, LLC	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		3,772	3,772		20,637		20,637
272	Macquarie Energy, LLC	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT		1,872	1,872		10,248		10,248
273	Macquarie Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		135	135		625		625
274	Macquarie Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		3,175	3,175		14,694		14,694
275	MAG Energy Solutions	NWMT	AVA	SFP	MONTANA OATT	MATL.NWMT	AVAT.NWMT		1,368	1,368		6,327		6,327
276	MAG Energy Solutions	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		7,893	7,893		36,519		36,519
277	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY		26,502	26,502		122,594		122,594
278	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF		12,285	12,285		56,829		56,829
279	MAG Energy Solutions	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	BRDY		16,449	16,449		76,311		76,311
280	MAG Energy Solutions	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	JEFF		16,623	16,623		76,843		76,843
281	MAG Energy Solutions	PACE	NWMT	SFP	MONTANA OATT	YTP	MATL.NWMT		168	168		777		777
282	MAG Energy Solutions	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		1,920	1,920		8,880		8,880
283	MAG Energy Solutions	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		182	182		843		843
284	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		3,688	3,688		17,058		17,058
285	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF		628	628		2,908		2,908
286	Mercuria Energy America, LLC	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		816	816		3,774		3,774
287	Mercuria Energy America, LLC	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	YTP		88,824	88,824		404,711		404,711
288	Mercuria Energy America, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		614	614		2,843		2,843
289	Mercuria Energy America, LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		52	52		242		242
290	Mercuria Energy America, LLC	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		25	25		116		116
291	Morgan Stanley Capital Group, Inc.	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		816	816		3,778		3,778
292	Morgan Stanley Capital Group, Inc.	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		3,360	3,360		15,540		15,540
293	Morgan Stanley Capital Group, Inc.	AVA	GWA	NF	MONTANA OATT	AVAT.NWMT	GLWND1		109	109		505		505
294	Morgan Stanley Capital Group, Inc.	AVA	GWA	NF	MONTANA OATT	AVAT.NWMT	GLWND2		135	135		625		625
295	Morgan Stanley Capital Group, Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT		50,550	50,550		235,068		235,068
296	Morgan Stanley Capital Group, Inc.	AVA	NWMT	SFP	MONTANA OATT	AVAT.NWMT	MATL.NWMT		87,048	87,048		416,906		416,906
297	Morgan Stanley Capital Group, Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY		110,400	110,400		504,150		504,150
298	Morgan Stanley Capital Group, Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		106	106		491		491
299	Morgan Stanley Capital Group, Inc.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		932	932		4,315		4,315
300	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND1		3,006	3,006		15,333		15,333
301	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND2		1,253	1,253		6,465		6,465
302	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		315,376	315,376		1,572,041		1,572,041
303	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		561	561		2,604		2,604
304	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	COLSTRIP		552	552		2,553		2,553
305	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	MATL.NWMT		261,627	261,627		1,426,445		1,426,445
306	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		1,781	1,781		10,465		10,465
307	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF		957	957		4,768		4,768
308	Morgan Stanley Capital Group, Inc.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	BRDY		1,680	1,680		9,870		9,870
309	Morgan Stanley Capital Group, Inc.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	JEFF		73,248	73,248		397,266		397,266
310	Morgan Stanley Capital Group, Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		2,061	2,061		9,542		9,542
311	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND1	AVAT.NWMT		15,483	15,483		71,966		71,966
312	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND2	AVAT.NWMT		6,937	6,937		32,351		32,351
313	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND1	BPAT.NWMT		126,287	126,287		637,878		637,878
314	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND2	BPAT.NWMT		72,558	72,558		369,465		369,465
315	Morgan Stanley Capital Group, Inc.	GWA	BPAT	SFP	MONTANA OATT	GLWND1	BPAT.NWMT		142,770	142,770		743,505		743,505
316	Morgan Stanley Capital Group, Inc.	GWA	BPAT	SFP	MONTANA OATT	GLWND2	BPAT.NWMT		87,840	87,840		452,430		452,430
317	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND1	MATL.NWMT		22,920	22,920		123,772		123,772
318	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND1	NWMT.SYSTEM		187	187		937		937
319	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	MATL.NWMT		7,231	7,231		38,733		38,733
320	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	NWMT.SYSTEM		98	98		574		574
321	Morgan Stanley Capital Group, Inc.	GWA	NWMT	SFP	MONTANA OATT	GLWND2	NWMT.SYSTEM		52,434	52,434		269,265		269,265
322	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	BRDY		14,825	14,825		80,032		80,032
323	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	JEFF		16,095	16,095		79,313		79,313
324	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	YTP		456	456		2,679		2,679
325	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	BRDY		10,382	10,382		53,390		53,390
326	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	JEFF		2,075	2,075		12,197		12,197
327	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	YTP		25	25		147		147
328	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND1	BRDY		22,032	22,032		124,578		124,578
329	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND1	JEFF		23,232	23,232		136,488		136,488
330	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND2	BRDY		2,232	2,232		13,113		13,113
331	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND2	JEFF		10,800	10,800		63,450		63,450
332	Morgan Stanley Capital Group, Inc.	GWA	WAPA	NF	MONTANA OATT	GLWND1	CROSSOVER		1,072	1,072		5,566		5,566
333	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	HARDIN	AVAT.NWMT		3,690	3,690		17,083		17,083
334	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT		128	128		593		593
335	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		41,938	41,938		197,085		197,085
336	Morgan Stanley Capital Group, Inc.	NWMT	AVA	SFP	MONTANA OATT	HARDIN	AVAT.NWMT		7,608	7,608		35,187		35,187
337	Morgan Stanley Capital Group, Inc.	NWMT	AVA	SFP	MONTANA OATT	MATL.NWMT	AVAT.NWMT		26,808	26,808		137,376		137,376
338	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		1,627	1,627		7,823		7,823
339	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	HARDIN	BPAT.NWMT		15,900	15,900		76,115		76,115
340	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT		439	439		2,070		2,070
341	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		202,992	202,992		997,297		997,297
342	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		50	50		294		294
343	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		600	600		2,775		2,775
344	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	HARDIN	BPAT.NWMT		3,816	3,816		17,649		17,649
345	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	KERR	BPAT.NWMT		2,496	2,496		12,744		12,744
346	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	MATL.NWMT	BPAT.NWMT		216,384	216,384		1,128,681		1,128,681
347	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	COLSTRIP	GLWND1		10	10		51		51
348	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	HARDIN	GLWND1		31	31		160		160
349	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	HARDIN	GLWND2		10	10		46		46
350	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND1		1,421	1,421		7,305		7,305
351	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND2		58	58		286		286
352	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	NWMTIMBALANC	GLWND1		3	3		14		14
353	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT		28,724	28,724		135,611		135,611
354	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	HARDIN	MATL.NWMT		31,000	31,000		149,423		149,423
355	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	HARDIN	NWMT.SYSTEM		51	51		270		270
356	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	KERR	MATL.NWMT		119	119		700		700
357	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	CANYONFERRY	MATL.NWMT		2,640	2,640		15,510		15,510
358	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	COLSTRIP	MATL.NWMT		129,544	129,544		677,604		677,604
359	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	HARDIN	MATL.NWMT		71,722	71,722		331,959		331,959
360	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	KERR	MATL.NWMT		3,839	3,839		21,258		21,258
361	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY		37,216	37,216		202,574		202,574
362	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF		41,164	41,164		228,562		228,562
363	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP		774	774		4,517		4,517
364	Morgan Stanley Capital Group, Inc.	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	BRDY		46,464	46,464		272,976		272,976
365	Morgan Stanley Capital Group, Inc.	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	JEFF		6,216	6,216		36,519		36,519
366	Morgan Stanley Capital Group, Inc.	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	YTP		600	600		3,525		3,525
367	Morgan Stanley Capital Group, Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER		1,088	1,088		5,710		5,710
368	Morgan Stanley Capital Group, Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	GREATFALLS		18	18		106		106
369	Morgan Stanley Capital Group, Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT		3,233	3,233		15,795		15,795
370	Morgan Stanley Capital Group, Inc.	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT		1,104	1,104		6,486		6,486
371	Morgan Stanley Capital Group, Inc.	PACE	NWMT	SFP	MONTANA OATT	YTP	MATL.NWMT		76,399	76,399		454,560		454,560
372	Morgan Stanley Capital Group, Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		15	15		88		88
373	Morgan Stanley Capital Group, Inc.	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		3,600	3,600		21,150		21,150
374	Morgan Stanley Capital Group, Inc.	PPW	GWA	NF	MONTANA OATT	BRDY	GLWND1		9	9		42		42
375	Morgan Stanley Capital Group, Inc.	WAPA	AVA	NF	MONTANA OATT	GREATFALLS	AVAT.NWMT		1,841	1,841		8,724		8,724
376	Morgan Stanley Capital Group, Inc.	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT		21,742	21,742		111,627		111,627
377	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY		1,982	1,982		10,703		10,703
378	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	JEFF		917	917		4,929		4,929
379	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	YTP		90	90		529		529
380	Morgan Stanley Capital Group, Inc.	WAPA	WAPA	NF	MONTANA OATT	GREATFALLS	CROSSOVER		252	252		1,417		1,417
381	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT		2,672	2,672		15,699		15,699
382	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	NF	MONTANA OATT	GREATFALLS	MATL.NWMT		28,066	28,066		159,169		159,169
383	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	SFP	MONTANA OATT	CROSSOVER	MATL.NWMT		55,150	55,150		297,775		297,775
384	Naturener Power Watch, LLC	GWA	GWA	SFP	MONTANA OATT	GLWND1	GLWND2		43,800	43,800		224,510		224,510
385	PacifiCorp	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		1,176	1,176		5,443		5,443
386	PacifiCorp	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		4,080	4,080		18,870		18,870
387	PacifiCorp	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP		155,184	155,184		712,532		712,532
388	PacifiCorp	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		600	600		2,775		2,775
389	PacifiCorp	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		150	150		695		695
390	PacifiCorp	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		4,049	4,049		18,744		18,744
391	PacifiCorp	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		127,728	127,728		587,194		587,194
392	PacifiCorp	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		19,200	19,200		112,700		112,700
393	PacifiCorp	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		951	951		4,559		4,559
394	PacifiCorp	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		309,120	309,120		1,411,620		1,411,620
395	PacifiCorp	PPW	NWMT	NF	MONTANA OATT	MLCK	JEFF		294	294		1,729		1,729
396	PacifiCorp	PPW	PPW	SFP	MONTANA OATT	BRDY	YTP		39,648	39,648		183,136		183,136
397	Portland General Electric Company	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		1,553	1,553		7,190		7,190
398	Portland General Electric Company	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP		264	264		1,222		1,222
399	Portland General Electric Company	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		1	1		6		6
400	Portland General Electric Company	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		345	345		1,597		1,597
401	Portland General Electric Company	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		250	250		1,158		1,158
402	Portland General Electric Company	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		11,643	11,643		56,876		56,876
403	Portland General Electric Company	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		50	50		232		232
404	Portland General Electric Company	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	NWMT.SYSTEM		6	6		28		28
405	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF		25	25		116		116
406	Portland General Electric Company	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		1	1		5		5
407	Portland General Electric Company	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		350	350		1,871		1,871
408	Powerex Corporation	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		1,055	1,055		4,885		4,885
409	Powerex Corporation	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		1,000	1,000		4,630		4,630
410	Powerex Corporation	BPAT	PPW	LFP	MONTANA OATT	BPAT.NWMT	BRDY	61	538,200	538,200	2,651,324			2,651,324
411	Powerex Corporation	BPAT	PPW	LFP	MONTANA OATT	BPAT.NWMT	JEFF	53	468,600	468,600	2,277,230			2,277,230
412	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		573	573		2,903		2,903
413	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF		3	3		18		18
414	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		9,833	9,833		49,242		49,242
415	Powerex Corporation	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		5,113	5,113		26,638		26,638
416	Powerex Corporation	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		1,091	1,091		5,051		5,051
417	Powerex Corporation	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT		173	173		801		801
418	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		450	450		2,646		2,646
419	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		7,488	7,488		41,112		41,112
420	Powerex Corporation	PPW	WAPA	NF	MONTANA OATT	JEFF	CROSSOVER		1,055	1,055		4,885		4,885
421	Powerex Corporation	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		1,216	1,216		5,630		5,630
422	Powerex Corporation	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		4,679	4,679		25,545		25,545
423	Public Service Company of Colorado	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		871	871		5,121		5,121
424	Public Service Company of Colorado	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		962	962		5,657		5,657
425	Puget Sound Energy Marketing	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		600	600		2,775		2,775
426	Puget Sound Energy Marketing	AVA	MLCK	NF	MONTANA OATT	COLSTRIP	MLCK		1	1		5		5
427	Puget Sound Energy Marketing	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		24,291	24,291		112,400		112,400
428	Puget Sound Energy Marketing	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		25	25		116		116
429	Puget Sound Energy Marketing	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		10,920	10,920		50,483		50,483
430	Puget Sound Energy Marketing	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		1	1		5		5
431	Puget Sound Energy Marketing	PPW	PPW	NF	MONTANA OATT	MLCK	BRDY		1	1		5		5
432	Rainbow Electric Marketing Corp.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		2,933	2,933		14,199		14,199
433	Rainbow Electric Marketing Corp.	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	YTP		62,568	62,568		285,227		285,227
434	Rainbow Electric Marketing Corp.	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		3,122	3,122		15,452		15,452
435	Rainbow Electric Marketing Corp.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		74	74		343		343
436	Rainbow Electric Marketing Corp.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		200	200		926		926
437	Rainbow Electric Marketing Corp.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		16,214	16,214		76,397		76,397
438	Rainbow Electric Marketing Corp.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	BRDY		2,400	2,400		14,100		14,100
439	Rainbow Electric Marketing Corp.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		9,127	9,127		44,603		44,603
440	Rainbow Electric Marketing Corp.	NWMT	BPAT	NF	MONTANA OATT	CANYONFERRY	BPAT.NWMT		1,200	1,200		5,550		5,550
441	Rainbow Electric Marketing Corp.	NWMT	BPAT	NF	MONTANA OATT	JUDITHGAP	BPAT.NWMT		200	200		926		926
442	Rainbow Electric Marketing Corp.	NWMT	BPAT	SFP	MONTANA OATT	JUDITHGAP	BPAT.NWMT		600	600		2,775		2,775
443	Rainbow Electric Marketing Corp.	NWMT	PPW	NF	MONTANA OATT	CANYONFERRY	BRDY		1,504	1,504		6,958		6,958
444	Rainbow Electric Marketing Corp.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		1,440	1,440		6,962		6,962
445	Rainbow Electric Marketing Corp.	NWMT	PPW	SFP	MONTANA OATT	CANYONFERRY	BRDY		696	696		3,219		3,219
446	Rainbow Electric Marketing Corp.	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		2,400	2,400		11,400		11,400
447	Rainbow Electric Marketing Corp.	NWMT	WAUW	NF	MONTANA OATT	NWMTIMBALANC	CROSSOVER		2	2		9		9
448	Rainbow Electric Marketing Corp.	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT		1,052	1,052		4,871		4,871
449	Rainbow Electric Marketing Corp.	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		600	600		3,525		3,525
450	Rainbow Electric Marketing Corp.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		39,631	39,631		189,848		189,848
451	Rainbow Electric Marketing Corp.	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		5,040	5,040		29,310		29,310
452	Rainbow Electric Marketing Corp.	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		750	750		4,160		4,160
453	Rainbow Electric Marketing Corp.	PPW	PPW	NF	MONTANA OATT	YTP	JEFF		60	60		278		278
454	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER		1,707	1,707		7,903		7,903
455	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	BRDY	GREATFALLS		216	216		1,000		1,000
456	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		5,123	5,123		26,226		26,226
457	Rainbow Electric Marketing Corp.	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT		536	536		2,855		2,855
458	Rainbow Electric Marketing Corp.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		18,321	18,321		85,338		85,338
459	Rainbow Electric Marketing Corp.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		3,949	3,949		22,424		22,424
460	Rainbow Electric Marketing Corp.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		12,386	12,386		61,957		61,957
461	Shell Energy North America	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT		3	3		14		14
462	Shell Energy North America	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		510	510		2,935		2,935
463	Shell Energy North America	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF		1	1		5		5
464	Shell Energy North America	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		599	599		3,298		3,298
465	Shell Energy North America	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		21,529	21,529		125,753		125,753
466	Shell Energy North America	NWMT	AVA	NF	MONTANA OATT	HOLTER	AVAT.NWMT		601	601		2,783		2,783
467	Shell Energy North America	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT		26	26		120		120
468	Shell Energy North America	NWMT	AVA	NF	MONTANA OATT	TFALLS	AVAT.NWMT		825	825		3,820		3,820
469	Shell Energy North America	NWMT	AVA	SFP	MONTANA OATT	HOLTER	AVAT.NWMT		600	600		2,775		2,775
470	Shell Energy North America	NWMT	AVA	SFP	MONTANA OATT	TFALLS	AVAT.NWMT		600	600		2,775		2,775
471	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		464	464		2,148		2,148
472	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT		88	88		437		437
473	Shell Energy North America	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		960	960		4,440		4,440
474	Shell Energy North America	NWMT	PACE	NF	MONTANA OATT	BGI	BRDY		304	304		1,773		1,773
475	Shell Energy North America	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		2,297	2,297		13,480		13,480
476	Shell Energy North America	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT		2,450	2,450		14,086		14,086
477	Shell Energy North America	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT		6,678	6,678		31,583		31,583
478	Shell Energy North America	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		11,739	11,739		53,946		53,946
479	Shell Energy North America	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		869	869		4,116		4,116
480	Shell Energy North America	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		22,588	22,588		114,284		114,284
481	Shell Energy North America	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		504	504		2,331		2,331
482	Shell Energy North America	PPW	NWMT	SFP	MONTANA OATT	BRDY	NWMT.SYSTEM		792	792		3,663		3,663
483	Shell Energy North America	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		16,850	16,850		77,600		77,600
484	Shell Energy North America	PPW	PPW	NF	MONTANA OATT	BRDY	MLCK		171	171		792		792
485	Shell Energy North America	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		1,520	1,520		7,046		7,046
486	Shell Energy North America	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER		50	50		294		294
487	Shell Energy North America	PPW	WAPA	SFP	MONTANA OATT	BRDY	GREATFALLS		360	360		1,665		1,665
488	Shell Energy North America	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT		10,729	10,729		49,979		49,979
489	Shell Energy North America	WAPA	AVA	SFP	MONTANA OATT	CROSSOVER	AVAT.NWMT		1,200	1,200		5,550		5,550
490	Shell Energy North America	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		35,306	35,306		197,781		197,781
491	Shell Energy North America	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		288	288		1,693		1,693
492	Shell Energy North America	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF		281	281		1,652		1,652
493	Shell Energy North America	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		40	40		185		185
494	Talen Energy Marketing, LLC	NWMT	BPAT	LFP	MONTANA OATT	GTFALLSNWMT	BPAT.NWMT		25	25
495	TEC Energy Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		93	93		431		431
496	Tenaska Power Services Co.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		230	230		1,065		1,065
497	Tenaska Power Services Co.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		130	130		764		764
498	Tenaska Power Services Co.	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		624	624		3,666		3,666
499	The Energy Authority	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		7	7		32		32
500	The Energy Authority	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		2,405	2,405		11,135		11,135
501	The Energy Authority	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		150	150		695		695
502	The Energy Authority	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		120	120		706		706
503	The Energy Authority	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		100	100		588		588
504	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		2,541	2,541		13,025		13,025
505	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF		310	310		1,435		1,435
506	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		13,609	13,609		64,440		64,440
507	The Energy Authority	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP		1,200	1,200		7,050		7,050
508	The Energy Authority	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		8,376	8,376		42,387		42,387
509	The Energy Authority	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		24	24		111		111
510	The Energy Authority	NWMT	PACE	NF	MONTANA OATT	TFALLS	YTP		481	481		2,227		2,227
511	The Energy Authority	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		47	47		276		276
512	The Energy Authority	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		2,962	2,962		13,714		13,714
513	The Energy Authority	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT		656	656		3,069		3,069
514	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		2,309	2,309		11,223		11,223
515	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		47,954	47,954		245,077		245,077
516	The Energy Authority	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		504	504		2,961		2,961
517	The Energy Authority	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		25	25		116		116
518	The Energy Authority	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		69	69		319		319
519	The Energy Authority	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT		25	25		116		116
520	The Energy Authority	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		16,427	16,427		87,111		87,111
521	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		770	770		4,434		4,434
522	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF		62	62		327		327
523	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		709	709		3,736		3,736
524	Transalta Energy Marketing (US) Inc.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		42	42		194		194
525	Transalta Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		1	1		5		5
526	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		440	440		2,587		2,587
527	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF		87	87		423		423
528	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		5,906	5,906		28,525		28,525
529	Transalta Energy Marketing (US) Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		12,614	12,614		67,424		67,424
530	Transalta Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		21,178	21,178		98,027		98,027
531	Transalta Energy Marketing (US) Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF		1	1		6		6
532	Transalta Energy Marketing (US) Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER		138	138		639		639
533	Transalta Energy Marketing (US) Inc.	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT		90	90		479		479
534	Transalta Energy Marketing (US) Inc.	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		3,600	3,600		21,150		21,150
535	Transalta Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		84	84		389		389
536	Transalta Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		23,815	23,815		120,526		120,526
537	Transalta Energy Marketing (US) Inc.	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		1,200	1,200		5,550		5,550
538	Transalta Energy Marketing (US) Inc.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		288	288		1,366		1,366
539	Transalta Energy Marketing (US) Inc.	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT		250	250		1,158		1,158
540	Transalta Energy Marketing (US) Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		27,584	27,584		145,055		145,055
541	Transalta Energy Marketing (US) Inc.	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT		312	312		1,443		1,443
542	Transalta Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		250	250		1,470		1,470
543	Transalta Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		659	659		3,051		3,051
544	Uniper Global Commodities North America LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		361	361		1,671		1,671
545	Vitol Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY		137,832	137,832		625,521		625,521
546	Vitol Inc.	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	YTP		12,432	12,432		57,424		57,424
547	Vitol Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		168	168		778		778
548	Vitol Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT		15	15		69		69
549	Vitol Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		6	6		28		28
550	Western Area Power Administration	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		5,600	5,600		31,928		31,928
551	Western Area Power Administration	NWMT	WAPA	NF	MONTANA OATT	CANYONFERRY	CROSSOVER		248,360	248,360		1,271,857		1,271,857
552	Western Area Power Administration	NWMT	WAPA	NF	MONTANA OATT	CANYONFERRY	GREATFALLS		992	992		4,593		4,593
553	Western Area Power Administration	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		69	69		319		319
554	Western Area Power Administration	WAPA	NWMT	NF	MONTANA OATT	CROSSOVER	NWMT.SYSTEM		1,178	1,178		5,454		5,454
555	Western Area Power Administration	WAPA	NWMT	NF	MONTANA OATT	GREATFALLS	NWMT.SYSTEM		17,472	17,472		89,749		89,749
556	Western Area Power Administration	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		1,336	1,336		6,186		6,186
557	Western Area Power Administration	WAPA	WAPA	NF	MONTANA OATT	CROSSOVER	GREATFALLS		374	374		1,732		1,732
558	Western Area Power Administration	WAPA	WAPA	NF	MONTANA OATT	GREATFALLS	CROSSOVER		146,070	146,070		697,957		697,957
559	Western Area Power Administration	WAPA	WAPA	SFP	MONTANA OATT	CROSSOVER	GREATFALLS		91,325	91,325		470,395		470,395
560	Western Area Power Administration	WAPA	WAPA	SFP	MONTANA OATT	GREATFALLS	CROSSOVER		86,390	86,390		513,000		513,000
561	SOUTH DAKOTA
562	BRYANT, CITY OF	WAPA	BRYANT	LFP	VOL 2	HURON 115 KV BUS	BRYANT 25 KV		3,946	3,946	29,545			29,545
563	GROTON, CITY OF	WAPA	GROTON	LFP	VOL 2	HURON 115 KV BUS	GROTON 69 KV		15,569	15,569	970			970
564	LANGFORD, CITY OF	WAPA	LANGFORD	LFP	VOL 2	HURON 115 KV BUS	LANGFORD 12.5 KV		2,764	2,764	20,527			20,527
565	Southwest Power Pool (SPP)	SPP	Various	LFP	SCH 7	Various	Various		0				220,596	(a) 220,596
566	Southwest Power Pool (SPP)	SPP	Various	NF	SCH 8	Various	Various						80,808	(b) 80,808
567	Southwest Power Pool (SPP)	SPP	Various	FNS	SCH 9	Various	Various		0				6,085,511	(c) 6,085,511
568	Southwest Power Pool (SPP)	SPP	Various	LFP	SCH 11	Various	Various						87,655	(d) 87,655
569	Rounding							1	1	1		8	1	7
35	TOTAL							1,206	13,745,363	13,745,363	38,792,042	33,134,119	6,474,571	78,400,732

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: RevenuesFromTransmissionOfElectricityForOthers

Firm and Non-Firm Point to Point Transmission Service.

(b) Concept: RevenuesFromTransmissionOfElectricityForOthers

Non-Firm Point to Point Transmission Service.

Network integration transmission service.

(d) Concept: RevenuesFromTransmissionOfElectricityForOthers

Firm and Non-Firm Point to Point Transmission Service.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	MONTANA
2	Vigilante Elec. Coop	OLF	32,869	32,869	56,896			56,896
3	Bonneville Power Admin	OLF					(a) 3,655,109	3,655,109
4	Southwester Power Pool (MT)	FNS	112,825	112,825	1,496,719			1,496,719
5	Sun River Elect Coop	OLF	4,120	4,120	22,662			22,662
6	Supply:
7	Avista	NF	4,398	4,398		44,102		44,102
8	Bonneville Power Admin	NF	444,503	444,503		1,285,793		1,285,793
9	Idaho Power Company	NF	240	240		1,874		1,874
10	Seattle City Light	NF	5,827	5,827		7,632		7,632
11	SOUTH DAKOTA
12	East River	FNS			6,934			6,934
13	West Central Elect COOP	FNS			2,441			2,441
14	OtterTail Power (for MISO)	FNS			981			981
15	Southwest Power Pool	FNS			19,959,323			19,959,323
16	Rounding				1	1		2
	TOTAL		604,782	604,782	21,543,993	1,339,400	3,655,109	26,538,502

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers

Monthly system usage fee.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	635,033
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities	227,588
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Universal Systems Benefit Charge	10,465,306
7	Board of Directors	1,866,390
8	Amortization of upfront fees	131,053
9	Our Portion of Shared Generation	1,188,193
10	Human Resources general expenses (non-labor and not provided for elsewhere)	31,373
11	Miscellaneous	34,595
46	MiscellaneousGeneralExpenses TOTAL	(a) 14,579,531

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: MiscellaneousGeneralExpenses


	Montana Operations	South Dakota Operations	Total 930.2
Universal System Benefits Charge	10,465,306	—	10,465,306
Our Portion of Shared Ownership Gen	1,188,193	—	1,188,193
	11,653,499	—	11,653,499

Board of Directors Fees	1,603,519	262,872	1,866,391
Shareholder Expense	195,533	32,055	227,588
Industry & Association Dues	374,103	260,930	635,033
Amortization of upfront fees	112,595	18,458	131,053
Human Resources general expenses (non-labor and not provided for elsewhere)	26,444	4,929	31,373
Miscellaneous	28,217	6,377	34,594
	2,340,411	585,621	2,926,032

Total Account 930.2	13,993,910	585,621	14,579,531

Montana Operations Miscellaneous General Expenses account 930.2 includes $78,927 of Electric non-allowed Industry and Association Dues, which is removed for rate making purposes.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			1,543,432		1,543,432
2	Steam Production Plant	7,453,028				7,453,028
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional	10,119,989				10,119,989
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	18,719,255		3,537		18,722,792
7	Transmission Plant	27,783,928		502,897		28,286,825
8	Distribution Plant	60,164,686		25,379		60,139,307
9	Regional Transmission and Market Operation
10	General Plant	10,164,021				10,164,021
11	Common Plant-Electric	5,349,605		5,292,097		10,641,702
12	TOTAL	(a) 139,754,512		(b) 7,316,584		147,071,096

B. Basis for Amortization Charges
The basis used to compute the charges is the ending plant balance. The basis is different from the preceding year due to net plant additions throughout the year. There has been no update to the authorized rates in the current year. The rates used to compute amortization charges for 'Intangible Plant - Electric' (Account 404) are as follows: 302 Intangible Plant: Franchises and Consents 2.00%; 303 Intangible Plant: Five Year Software 20%; 303 Intangible Plant: BPA Rattlesnake Line 3.34%; 340.2 Intangible Plant: Other Production Land Rights 3.34%; 340.2 Intangible Plant: Spion Kop Land Rights 4.00%; 350.2 Intangible Plant: Transmission Land Rights 1.51%; 360.2 Intangible Plant: Distribution Land Rights (0.59%); 4303.5 Intangible Plant: Five Year Common Software 20%; and 4303.1 Intangible Plant: Ten Year Common Software 10%. For FERC reporting purposes, common amortization expense is allocated to electric and gas amortization as cmmon amortization expense is not reported on the FERC forms. The rate used to allocate the common amortization expense to electric is 72.00%.

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments

Montana Operations


A. Summary of Depreciation and Amortization Charges


Line No.	Functional Classification (a)	Depreciation Expense (Account 403) (b)	Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	Amortization of Limited Term Electric Plant (Account 404) (d)	Amortization of Other Electric Plant (Acc 405) (e)	Total
1	Intangible Plant	—	—	1,539,248	—	1,539,248
2	Steam Production Plant	3,595,636	—	—	—	3,595,636
3	Nuclear Production Plant	—	—	—	—
4	Hydraulic Production Plant‐Conventional	10,119,989	—	—	—	10,119,989
5	Hydraulic Production Plant‐Pumped Storage	—	—	—	—	—
6	Other Production Plant	11,192,011	—	3,537	—	11,195,548
7	Transmission Plant	21,239,914	—	502,897	—	21,742,811
8	Distribution Plant	49,491,976	—	(25,379)	—	49,466,597
9	General Plant	8,569,111	—	—	—	8,569,111
10	Common Plant-Electric	3,105,342	—	3,909,037	—	7,014,379
11	TOTAL	101,616,849	—	5,329,476	—	113,243,319

South Dakota Operations


Line No.	Functional Classification (a)	Depreciation Expense (Account 403) (b)	Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	Amortization of Limited Term Electric Plant (Account 404) (d)	Amortization of Other Electric Plant (Acc 405) (e)	Total
1	Intangible Plant	—	—	4,184	—	4,184
2	Steam Production Plant	3,857,392	—	—	—	3,857,392
3	Nuclear Production Plant	—	—	—	—
4	Hydraulic Production Plant‐Conventional	—	—	—	—
5	Hydraulic Production Plant‐Pumped Storage	—	—	—	—
6	Other Production Plant	7,527,244	—	—	—	7,527,244
7	Transmission Plant	6,544,014	—	—	—	6,544,014
8	Distribution Plant	10,672,710	—	—	—	10,672,710
9	General Plant	1,594,910	—	—	—	1,594,910
10	Common Plant-Electric	2,244,264	—	1,383,059	—	3,627,323
11	TOTAL	30,533,748	—	1,387,243	—	33,827,777

(b) Concept: AmortizationOfLimitedTermPlantOrProperty


B. Basis for Amortization Charges

The following represents transmission and distribution land rights and computer software amortization applicable to or allocated to the electric department. These costs are amortized over the expected life of the transmission or distribution plant or computer software.


Plant Amount	Costs Being Amortized		Amortization Period (Years)	Annual Amortization		Allocated to Electric

302	$	19,288,558	50	$	312,240	312,240
303	6,406,682		5	1,203,986		1,203,986
303	868,284		30	29,000		29,000
340.2	89,998		25, 30	3,537		3,537
350.2	33,304,418		58	502,897		502,897
360.2	4,303,367		60	(25,390)		(25,390)
4303	40,720,303		5, 10	7,075,719		5,308,562

	104,981,610			9,101,989		7,334,832

The above schedule represents a full year amortization calculation. Further, per our last Montana rate case, our Montana plant assets do not begin amortization until the year subsequent to being placed into service. Our South Dakota plant assets do not begin amortization until the quarter subsequent to being placed into service.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	Annual Charges Under the Omnibus
2	Reconciliation Act of 1986
3	FERC Order No. 472	1,287,562		1,287,562		Electric	928	1,287,562
4	Montana PSC Electric & Gas Rate Filings		593,654	593,654		Electric	928	517,051
5	Montana PSC Electric & Gas Rate Filings					Gas	928	76,603
6	FERC Administrative Charges Allocated to
7	Generating Stations Under Project License	1,436,367		1,436,367		Electric	928	1,436,367
46	TOTAL	2,723,929	593,654	(a) 3,317,583				3,317,583

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: RegulatoryCommissionExpensesAmount

Montana electric regulatory commission expenses totaled $3,238,766 for 2022. This includes $1,344,179 in expenses that are transmission specific.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	8,575,110
4	SalariesAndWagesElectricOperationTransmission Transmission	7,260,437
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	12,716,044
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	4,468,787
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	3,530,297
9	SalariesAndWagesElectricOperationSales Sales	2,938
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	27,747,032
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	64,300,645
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	1,889,530
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	2,060,598
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	9,583,334
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	2,915,776
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	16,449,238
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	10,464,640
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	9,321,035
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	22,299,378
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	4,468,787
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	3,530,297
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)	2,938
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	30,662,808
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	80,749,883		80,749,883
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)	1,673,186
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply	67,654
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing	569,252
35	SalariesAndWagesGasOperationTransmission Transmission	4,244,294
36	SalariesAndWagesGasOperationDistribution Distribution	8,366,893
37	SalariesAndWagesGasCustomerAccounts Customer Accounts	1,861,656
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational	1,551,604
39	SalariesAndWagesGasSales Sales	1,155
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General	11,113,472
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)	29,449,166
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)	168,731
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing	132,596
47	SalariesAndWagesGasMaintenanceTransmission Transmission	982,217
48	SalariesAndWagesGasMaintenanceDistribution Distribution	3,020,117
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General	1,234,981
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)	5,538,642
51	SalariesAndWagesGasOperationAndMaintenanceAbstract Total Operation and Maintenance
52	SalariesAndWagesGasProductionManufacturedGas Production-Manufactured Gas (Enter Total of lines 31 and 43)
53	SalariesAndWagesGasProductionNaturalGas Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,	1,841,917
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)	67,654
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru	701,848
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)	5,226,511
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)	11,387,010
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)	1,861,656
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)	1,551,604
60	SalariesAndWagesGasSales Sales (Line 39)	1,155
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)	12,348,453
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)	34,987,808		34,987,808
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance	48,789		48,789
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	115,786,480		115,786,480
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	28,885,430		28,885,430
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant	10,107,803		10,107,803
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):	27,571		27,571
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	39,020,804		39,020,804
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription A/R Associated Companies (Account 146)	946,327		946,327
80	SalariesAndWagesOtherAccountsDescription Expenses of Non-Utility Operations (Account 417)	1,047,445		1,047,445
81	SalariesAndWagesOtherAccountsDescription Montana Operations Detail Footnote
82	SalariesAndWagesOtherAccountsDescription South Dakota Detail Footnote
83	SalariesAndWagesOtherAccountsDescription
84	SalariesAndWagesOtherAccountsDescription
85	SalariesAndWagesOtherAccountsDescription
86	SalariesAndWagesOtherAccountsDescription
87	SalariesAndWagesOtherAccountsDescription
88	SalariesAndWagesOtherAccountsDescription
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	1,993,772		1,993,772
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	156,801,056		(a)(b) 156,801,056

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: SalariesAndWagesGeneralExpense

Montana Operations


DISTRIBUTION OF SALARIES AND WAGES
LINE NO.	CLASSIFICATION	DIRECT PAYROLL DISTRIBUTION	ALLOCATION OF PAYROLL CHARGED FOR CLEARING ACCOUNTS	TOTAL
	(a)	(b)	(c)	(d)
1	ELECTRIC
2	OPERATION
3	PRODUCTION	7,980,958
4	TRANSMISSION	6,711,170
5	REGIONAL MARKET	0
6	DISTRIBUTION	10,306,790
7	CUSTOMER ACCOUNTS	4,086,641
8	CUSTOMER SERVICE & INFORMATION	2,453,162
9	SALES	2,083
10	ADMINISTRATIVE & GENERAL	24,243,859
11	TOTAL OPERATION	55,784,663
12	MAINTENANCE
13	PRODUCTION	1,633,164
14	TRANSMISSION	1,804,244
15	REGIONAL MARKET	0
16	DISTRIBUTION	7,980,302
17	ADMINISTRATIVE & GENERAL	2,721,866
18	TOTAL MAINTENANCE	14,139,576
19	TOTAL OPERATION & MAINTENANCE
20	PRODUCTION	9,614,122
21	TRANSMISSION	8,515,414
22	REGIONAL MARKET	0
23	DISTRIBUTION	18,287,092
24	CUSTOMER ACCOUNTS	4,086,641
25	CUSTOMER SERVICE & INFORMATION	2,453,162
26	SALES	2,083
27	ADMINISTRATIVE & GENERAL	26,965,725
28	TOTAL OPERATION & MAINTENANCE	69,924,239	0	69,924,239
29	GAS
30	OPERATION
31	PRODUCTION - MANUFACTURED GAS	0
32	PRODUCTION - NAT. GAS	1,673,186
33	OTHER GAS SUPPLY	67,654
34	STORAGE, LNG TERMINAL PROCESSING	569,252
35	TRANSMISSION	4,215,772
36	DISTRIBUTION	4,698,997
37	CUSTOMER ACCOUNTS	1,454,227
38	CUSTOMER SERVICE & INFORMATION	835,543
39	SALES	771
40	ADMINISTRATIVE & GENERAL	8,388,552
41	TOTAL OPERATION	21,903,954
42	MAINTENANCE
43	PRODUCTION - MANUFACTURED GAS	0
44	PRODUCTION - NATURAL GAS	168,731


45	OTHER GAS SUPPLY	0
46	STORAGE, LNG TERMINAL PROCESSING	132,596
47	TRANSMISSION	978,898
48	DISTRIBUTION	2,071,198
49	ADMINISTRATIVE & GENERAL	1,088,368
50	TOTAL MAINTENANCE	4,439,791
	GAS (CONTINUED)
51	TOTAL OPERATION & MAINTENANCE
52	PRODUCTION - MANUFACTURED GAS	0
53	PRODUCTION - NATURAL GAS	1,841,917
54	OTHER GAS SUPPLY	67,654
55	STORAGE, LNG TERMINAL PROCESSING	701,848
56	TRANSMISSION	5,194,670
57	DISTRIBUTION	6,770,195
58	CUSTOMER ACCOUNTS	1,454,227
59	CUSTOMER SERVICE & INFORMATION	835,543
60	SALES	771
61	ADMINISTRATIVE & GENERAL	9,476,920
62	TOTAL OPERATION & MAINTENANCE	26,343,745	0	26,343,745
63	OTHER UTILITY DEPARTMENTS
64	OPERATION & MAINTENANCE	48,789	0	48,789
65	TOTAL ALL UTILITY DEPARTMENTS	96,316,773	0	96,316,773
66	UTILITY PLANT
67	CONSTRUCTION (BY UTILITY DEPARTMENT)
68	ELECTRIC PLANT	23,631,920	0	23,631,920
69	GAS PLANT	8,069,353	0	8,069,353
70	OTHER	27,571	0	27,571
71	TOTAL CONSTRUCTION	31,728,844	0	31,728,844
72	PLANT REMOVAL
73	ELECTRIC PLANT	0	0	0
74	GAS PLANT	0		0
75	OTHER	0		0
76	TOTAL PLANT REMOVAL	0	0	0
77	OTHER ACCOUNTS (SPECIFY):
78	A/R ASSOCIATED COMPANIES (ACCT 146)	6,597,775		6,597,775
79	A/R MISCELLANEOUS (ACCT 143)	0		0
80	SEVERANCE PAYMENTS (ACCT 182)			0
81	EXPENSES OF NON-UTILITY OP (ACCT 417)	1,021,354		1,021,354
82	OTHER			0
83
98	TOTAL OTHER ACCOUNTS	7,619,129	0	7,619,129
99	TOTAL SALARIES AND WAGES	135,664,746	0	135,664,746

(b) Concept: SalariesAndWagesGeneralExpense

South Dakota Operations

DISTRIBUTION OF SALARIES AND WAGES

LINE NO.

CLASSIFICATION

DIRECT PAYROLL DISTRIBUTION

ALLOCATION OF PAYROLL CHARGED FOR CLEARING ACCOUNTS

TOTAL

(a)

(b)

(c)

(d)

ELECTRIC

OPERATION

PRODUCTION

594,152

TRANSMISSION

549,267


5	REGIONAL MARKET	0
6	DISTRIBUTION	2,409,254
7	CUSTOMER ACCOUNTS	382,146
8	CUSTOMER SERVICE & INFORMATION	1,077,135
9	SALES	855
10	ADMINISTRATIVE & GENERAL	3,503,173
11	TOTAL OPERATION	8,515,982
12	MAINTENANCE
13	PRODUCTION	256,366
14	TRANSMISSION	256,354
15	REGIONAL MARKET	0
16	DISTRIBUTION	1,603,032
17	ADMINISTRATIVE & GENERAL	193,910
18	TOTAL MAINTENANCE	2,309,662
19	TOTAL OPERATION & MAINTENANCE
20	PRODUCTION	850,518
21	TRANSMISSION	805,621
22	REGIONAL MARKET	0
23	DISTRIBUTION	4,012,286
24	CUSTOMER ACCOUNTS	382,146
25	CUSTOMER SERVICE & INFORMATION	1,077,135
26	SALES	855
27	ADMINISTRATIVE & GENERAL	3,697,083
28	TOTAL OPERATION & MAINTENANCE	10,825,644	0	10,825,644
29	GAS
30	OPERATION
31	PRODUCTION - MANUFACTURED GAS	0
32	PRODUCTION - NAT. GAS	0
33	OTHER GAS SUPPLY	0
34	STORAGE, LNG TERMINAL PROCESSING	0
35	TRANSMISSION	28,522
36	DISTRIBUTION	3,667,896
37	CUSTOMER ACCOUNTS	407,429
38	CUSTOMER SERVICE & INFORMATION	716,061
39	SALES	384
40	ADMINISTRATIVE & GENERAL	2,724,920
41	TOTAL OPERATION	7,545,212
42	MAINTENANCE
43	PRODUCTION - MANUFACTURED GAS	0
44	PRODUCTION - NATURAL GAS	0
45	OTHER GAS SUPPLY	0
46	STORAGE, LNG TERMINAL PROCESSING	0
47	TRANSMISSION	3,319
48	DISTRIBUTION	948,919
49	ADMINISTRATIVE & GENERAL	146,613
50	TOTAL MAINTENANCE	1,098,851
	GAS (CONTINUED)
51	TOTAL OPERATION & MAINTENANCE
52	PRODUCTION - MANUFACTURED GAS	0
53	PRODUCTION - NATURAL GAS	0
54	OTHER GAS SUPPLY	0
55	STORAGE, LNG TERMINAL PROCESSING	0
56	TRANSMISSION	31,841
57	DISTRIBUTION	4,616,815
58	CUSTOMER ACCOUNTS	407,429


59	CUSTOMER SERVICE & INFORMATION	716,061
60	SALES	384
61	ADMINISTRATIVE & GENERAL	2,871,533
62	TOTAL OPERATION & MAINTENANCE	8,644,063	0	8,644,063
63	OTHER UTILITY DEPARTMENTS
64	OPERATION & MAINTENANCE
65	TOTAL ALL UTILITY DEPARTMENTS	19,469,707	0	19,469,707
66	UTILITY PLANT
67	CONSTRUCTION (BY UTILITY DEPARTMENT)
68	ELECTRIC PLANT	5,253,510	0	5,253,510
69	GAS PLANT	2,038,450	0	2,038,450
70	OTHER	0	0	0
71	TOTAL CONSTRUCTION	7,291,960	0	7,291,960
72	PLANT REMOVAL
73	ELECTRIC PLANT	0	0	0
74	GAS PLANT	0		0
75	OTHER	0		0
76	TOTAL PLANT REMOVAL	0	0	0
77	OTHER ACCOUNTS (SPECIFY):
78	A/R ASSOCIATED COMPANIES (ACCT 146)	9,047,610		9,047,610
79	A/R MISCELLANEOUS (ACCT 143)	0		0
80	SEVERANCE PAYMENTS (ACCT 182)			0
81	EXPENSES OF NON-UTILITY OP (ACCT 417)	26,091	0
82	OTHER			0
83
98	TOTAL OTHER ACCOUNTS	9,073,701	0	9,073,701
99	TOTAL SALARIES AND WAGES	35,835,368	0	35,835,368

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

COMMON UTILITY PLANT AND EXPENSES

Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.
Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation.
Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.


NORTHWESTERN ENERGY - CONSOLIDATED COMMON UTILITY PLANT

	Item # 1
	Common Utility Plant at December 31, 2022

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	64,206,178	47,805,117	16,401,061

C389	Land & Land Rights	5,886,102	4,284,806	1,601,296

C390	Structures & Improvements	116,123,999	87,021,999	29,102,000

C391	Office Furniture & Equipment	23,293,692	17,852,564	5,441,128

C392	Transportation Equipment	10,251,782	7,835,747	2,416,035

C393	Stores Equipment	35,559	29,870	5,689

C394	Tools/Shop/Garage Equipment	206,328	173,012	33,316

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	2,299,056	1,931,207	367,849

C397	Communication Equipment	40,690,491	24,003,429	16,687,062

C398	Miscellaneous	838,012	607,289	230,723

	Subtotal	263,831,199	191,545,040	72,286,159


Construction Work in Progress		17,177,442

	Total	281,008,641


NORTHWESTERN ENERGY - MONTANA COMMON UTILITY PLANT

	Item # 1
	Common Utility Plant at December 31, 2022

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	51,067,275	36,768,438	14,298,837

C389	Land & Land Rights	4,669,761	3,263,080	1,406,681

C390	Structures & Improvements	78,153,859	55,127,082	23,026,777

C391	Office Furniture & Equipment	14,219,847	10,230,535	3,989,312

C392	Transportation Equipment	6,464,579	4,654,497	1,810,082

C393	Stores Equipment	0	0	0

C394	Tools/Shop/Garage Equipment	3,036	2,247	789

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	0	0	0

C397	Communication Equipment	36,150,763	20,190,057	15,960,706

C398	Miscellaneous	812,198	585,605	226,593

	Subtotal	191,541,318	130,821,541	60,719,777


Construction Work in Progress		15,414,240


NORTHWESTERN ENERGY - SOUTH DAKOTA COMMON UTILITY PLANT

	Item # 1
	Common Utility Plant at December 31, 2022

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	13,138,904	11,036,679	2,102,225

C389	Land & Land Rights	1,216,339	1,021,725	194,614

C390	Structures & Improvements	37,970,139	31,894,917	6,075,222

C391	Office Furniture & Equipment	9,073,844	7,622,029	1,451,815

C392	Transportation Equipment	3,787,204	3,181,251	605,953

C393	Stores Equipment	35,559	29,870	5,689

C394	Tools/Shop/Garage Equipment	203,292	170,765	32,527

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	2,299,056	1,931,207	367,849

C397	Communication Equipment	4,539,729	3,813,372	726,357

C398	Miscellaneous	25,815	21,685	4,130

	Subtotal	72,289,881	60,723,500	11,566,381


Construction Work in Progress		1,763,202	1,481,090	282,112

	Total	74,053,083


NORTHWESTERN ENERGY - CONSOLIDATED COMMON UTILITY ACCUMULATED DEPRECIATION

	Item # 2
	Common Utility Accumulated Depreciation Reserve At December 31, 2022

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	(20,987,010)	(15,723,461)	(5,263,549)

C389	Land & Land Rights	164,360	116,444	47,916

C390	Structures & Improvements	(20,250,076)	(15,535,544)	(4,714,532)

C391	Office Furniture & Equipment	(5,956,767)	(4,352,868)	(1,603,899)

C392	Transportation Equipment	(2,706,872)	(2,210,325)	(496,547)

C393	Stores Equipment	(7,112)	(5,974)	(1,138)

C394	Tools/Shop/Garage Equipment	(69,961)	(58,767)	(11,194)

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	(988,625)	(830,445)	(158,180)

C397	Communication Equipment	(21,843,755)	(12,777,345)	(9,066,410)

C398	Miscellaneous	(19,608)	934	(20,542)

	Total	(72,665,426)	(51,377,351)	(21,288,075)


NORTHWESTERN ENERGY - MONTANA COMMON UTILITY ACCUMULATED DEPRECIATION

	Item # 2
	Common Utility Accumulated Depreciation Reserve At December 31, 2022

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	15,880,225	11,433,762	4,446,463

C389	Land & Land Rights	(164,360)	(116,444)	(47,916)

C390	Structures & Improvements	9,825,478	6,778,882	3,046,596

C391	Office Furniture & Equipment	5,349,647	3,842,887	1,506,760

C392	Transportation Equipment	528,726	380,683	148,043

C393	Stores Equipment

C394	Tools/Shop/Garage Equipment

C395	Laboratory Equipment

C396	Power Operated Equipment

C397	Communication Equipment	18,360,823	9,851,682	8,509,141

C398	Miscellaneous	145,036	104,426	40,610

	Total	49,925,575	32,275,878	17,649,697


NORTHWESTERN ENERGY - SOUTH DAKOTA COMMON UTILITY ACCUMULATED DEPRECIATION

	Item # 2
	Common Utility Accumulated Depreciation Reserve At December 31, 2022

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	5,106,784	4,289,699	817,085

C389	Land & Land Rights	0	0	0

C390	Structures & Improvements	10,424,599	8,756,663	1,667,936

C391	Office Furniture & Equipment	607,120	509,981	97,139

C392	Transportation Equipment	2,178,145	1,829,642	348,503

C393	Stores Equipment	7,112	5,974	1,138

C394	Tools/Shop/Garage Equipment	69,961	58,767	11,194

C395	Laboratory Equipment

C396	Power Operated Equipment	988,625	830,445	158,180

C397	Communication Equipment	3,482,931	2,925,662	557,269

C398	Miscellaneous	(125,429)	(105,360)	(20,069)

	Total	22,739,848	19,101,473	3,638,375


NORTHWESTERN ENERGY - COMMON UTILITY PLANT EXPENSES FOR THE YEARS ENDING DECEMBER 31, 2022

Item #3

Common Expenses	General Building	Real Estate & Personal Property Tax	Depreciation & Amortization	Total

Electric:

Depreciation			5,349,605	5,349,605
Amortization			5,292,097	5,292,097
Taxes Other than Income		8,352,624		8,352,624
Administrative & General	4,495,656			4,495,656

Subtotal	4,495,656	8,352,624	10,641,702	23,489,982

Natural Gas				10,110,377

Total Common Expense				33,600,359

(1)General building expense is allocated to departmental expense accounts based on estimated facility utilization.

(2)Real Estate & Personal Property Taxes are allocated to departmental expense accounts based on the estimated facility utilization.

(3)Depreciation & Amortization expense is allocated to utility departmental expense accounts based on the estimated individual facility utilization applicable to the depreciable common plant.

ITEM #4

FERC staff recommendation dated January 19, 1967 gave approval for the use of the common plant classification.


NORTHWESTERN ENERGY - MONTANA UTILITY PLANT EXPENSES FOR THE YEARS ENDING DECEMBER 31, 2022

Item #3

Common Expenses	General Building	Real Estate & Personal Property Tax	Depreciation & Amortization	Total

Electric:

Depreciation			3,105,342	3,105,342
Amortization			3,909,037	3,909,037
Taxes Other than Income		8,352,624		8,352,624
Administrative & General	3,883,833			3,883,833

Subtotal	3,883,833	8,352,624	7,014,379	19,250,836

Natural Gas				8,270,578

Total Common Expense				27,521,414

(1)General building expense is allocated to departmental expense accounts based on estimated facility utilization.

(2)Real Estate & Personal Property Taxes are allocated to departmental expense accounts based on the estimated facility utilization.

(3)Depreciation & Amortization expense is allocated to utility departmental expense accounts based on the estimated individual facility utilization applicable to the depreciable common plant.

ITEM #4

FERC staff recommendation dated January 19, 1967 gave approval for the use of the common plant classification.


NORTHWESTERN ENERGY - SOUTH DAKOTA UTILITY PLANT EXPENSES FOR THE YEARS ENDING DECEMBER 31, 2022

Item #3

Common Expenses	General Building	Real Estate & Personal Property Tax	Depreciation & Amortization	Total

Electric:

Depreciation			2,244,263	2,244,263
Amortization			1,383,059	1,383,059
Taxes Other than Income		—		—
Administrative & General	611,823			611,823

Subtotal	611,823		3,627,322	4,239,145

Natural Gas				690,919

Total Common Expense				4,930,064

(1)General building expense is allocated to departmental expense accounts based on estimated facility utilization.

(2)Real Estate & Personal Property Taxes are allocated to departmental expense accounts based on the estimated facility utilization.

(3)Depreciation & Amortization expense is allocated to utility departmental expense accounts based on the estimated individual facility utilization applicable to the depreciable common plant.

ITEM #4

FERC staff recommendation dated January 19, 1967 gave approval for the use of the common plant classification.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)	29,488,892	35,471,122	84,038,633	44,388,003
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)	26,809,262	34,880,516	87,574,785	38,877,321
4	Transmission Rights
5	Ancillary Services	24,860	25,015	25,323	18,030
6	Other Items (list separately)
7	Day Ahead & Real Time Admin	87,010	87,550	88,630	63,104
8	Market Monitoring & Compliance	12,430	12,507	12,661	9,015
46	TOTAL	56,422,454	70,476,710	171,740,032	83,355,473

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch				(a) 13,723,084	MWh	1,875,805
2	Reactive Supply and Voltage
3	Regulation and Frequency Response				(b) 5,849,829	MWh	1,131,370
4	Energy Imbalance	31,727,023,317	kWh	8,322,444
5	Operating Reserve - Spinning				228	MWh	1,359,407
6	Operating Reserve - Supplement				228	MWh	1,289,846
7	Other				506,260	MWh	14,646,113
8	Total (Lines 1 thru 7)	(c) 31,727,023,317		8,322,444	20,079,629		20,302,541

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AncillaryServicesSoldNumberOfUnits

Transmission Customers are billed under the formula rate as approved in FERC docket ER19-1756-000. For more information on the NorthWestern Energy OATT see OASIS at https://oasis.oati.com/NWMT.


	Number of Units (e)	Unit of Measure (f)	Dollars (g)
Scheduling, System Control and Dispatch Network	5,117,120	MWh	775,967
Scheduling, System Control and Dispatch Point-to-Point	8,605,964	MWh	1,099,839
	13,723,084		1,875,806

(b) Concept: AncillaryServicesSoldNumberOfUnits

Transmission Customers are billed under the formula rate as approved in FERC docket ER19-1756. For more information on the NorthWestern Energy OATT see OASIS at https://oasis.oati.com/NWMT.


		Number of Units (e)	Unit of Measure (f)	Dollars (g)
Regulation and Frequency Responses Load Network Cust	Schedule 3 Load	4,204,120	MWh	884,268
Regulation and Frequency Responses Non Ver Network Cust	Schedule 3 Non Ver	1,654	MW	99,418
Regulation and Frequency Response Point to Point Cust	Schedule 3a Ver	24,331	MWh	14,298
Regulation and Frequency Response Point to Point Cust	Schedule 3a Non Ver	1,619,724	MWh	133,386

		5,849,829		1,131,370

This schedule represents Montana Operations only.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: Montana Operations
1	January	1,947	5	19	1,046	707	78	12	7,405
2	February	1,982	23	8	1,042	749	78	12	3,969
3	March	1,803	10	8	1,052	704	78	12	2,634
4	Total for Quarter 1				3,140	2,160	234	36	14,008
5	April	1,621	14	9	1,059	635	250	12	2,997
6	May	1,450	20	9	1,056	589	250	12	1,872
7	June	1,791	28	17	1,041	688	275	12	3,033
8	Total for Quarter 2				3,156	1,912	775	36	7,902
9	July	1,991	29	17	1,041	696	275	12	3,104
10	August	2,052	1	17	1,051	702	275	12	2,764
11	September	1,813	7	16	1,064	600	275	0	5,593
12	Total for Quarter 3				3,156	1,998	825	24	11,461
13	October	1,535	28	9	1,063	637	275	0	2,180
14	November	1,902	18	9	1,083	751	275	0	4,902
15	December	2,150	22	18	1,094	757	275	0	4,947
16	Total for Quarter 4				3,240	2,145	825	0	12,029
17	Total				12,692	8,215	2,659	96	45,400	0
	NAME OF SYSTEM: South Dakota Operations
1	January
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
13	October
14	November
15	December
16	Total for Quarter 4
17	Total

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: South Dakota Operations
1	January	300	6	8				315	15	330
2	February	288	22	10				302	14	316
3	March	228	11	9				240	12	252
4	Total for Quarter 1							857	41	898
5	April	251	14	10				263	12	275
6	May	281	12	16				291	10	301
7	June	302	20	16				316	14	330
8	Total for Quarter 2							870	36	906
9	July	248	18	16				258	10	268
10	August	238	5	16				250	12	262
11	September	267	1	17				281	14	295
12	Total for Quarter 3							789	36	825
13	October	146	25	20				154	8	162
14	November	219	30	8				231	12	243
15	December	263	22	18				278	15	293
16	Total for Quarter 4							663	35	698
17	Total Year to Date/Year							3,179	148	3,327

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2022-12-31

Year/Period of Report

End of:

2022

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	8,136,907
3	Steam	2,422,780	23	Requirements Sales for Resale (See instruction 4, page 311.)
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	1,058,843
5	Hydro-Conventional	2,192,732	25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	8,320
7	Other	1,000,028	27	Total Energy Losses	600,462
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	5,615,540	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	9,804,532
10	Purchases (other than for Energy Storage)	4,188,987
10.1	Purchases for Energy Storage	0
11	Power Exchanges:
12	Received	22,778
13	Delivered	22,773
14	Net Exchanges (Line 12 minus line 13)	5
15	Transmission For Other (Wheeling)
16	Received	13,745,363
17	Delivered	13,745,363
18	Net Transmission for Other (Line 16 minus line 17)	0
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	9,804,532

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

MONTHLY PEAKS AND OUTPUT
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: Montana Operations
29	January	787,796	72,612	2,037	5	19
30	February	676,659	113,763	2,072	23	8
31	March	714,044	94,680	1,893	10	8
32	April	565,071	106,742	1,883	14	9
33	May	608,181	52,418	1,712	20	9
34	June	591,958	96,516	2,078	28	17
35	July	577,833	72,109	2,278	29	17
36	August	704,156	60,394	2,339	1	17
37	September	690,234	83,980	2,088	7	16
38	October	690,781	96,120	1,810	28	9
39	November	681,141	124,211	2,177	18	9
40	December	764,840	85,298	2,425	22	18
41	Total	8,052,694	1,058,843
	NAME OF SYSTEM: South Dakota Operations
29	January	146,326	0	300	6	8
30	February	179,453	0	288	22	10
31	March	140,525	0	228	11	9
32	April	146,727	0	251	14	10
33	May	107,538	0	281	12	16
34	June	117,186	0	302	20	16
35	July	98,728	0	248	18	16
36	August	165,844	0	238	5	16
37	September	183,296	0	267	1	17
38	October	159,860	0	146	25	20
39	November	156,664	0	219	30	8
40	December	149,691	0	263	22	18
41	Total	1,751,838	0

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: Aberdeen #1	Plant Name: Aberdeen #2	Plant Name: Beethoven Wind	Plant Name: Big Stone	Plant Name: Bob Glanzer	Plant Name: Colstrip 4	Plant Name: Coyote	Plant Name: DGGS	Plant Name: Huron CT #1	Plant Name: Huron GT #2	Plant Name: Neal	Plant Name: Spion Kop	Plant Name: Two Dot	Plant Name: Yankton
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	(a) Combustion Turbine	Combustion Turbine	Wind Turbin	(b) Steam	(c) Gas Turbine	(d) Steam	(e) Steam	(f) Gas Turbine	(g) Combustion Turbine	(h) Combustion Turbine	(i) Steam	Wind Turbine	Wind Turbine	(j) Internal Combustion
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Conventional	Conventional	Wind Turbine	Conventional	Conventional	Boiler	Conventional	Conventional	Conventional	Conventional	Conventional	Wind Turbine	Wind Turbine	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1978	2013	2015	1975	2022	1984	1981	2010	1961	1991	1979	2012	2014	1974
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1978	2013	2015	1975	2022	1986	1981	2010	1961	1992	1979	2012	2014	1990
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	28.80	82.20	80.00	122.85	58.50	241.50	45.58	(k) 203.25	15.00	42.93	55.56	40.00	11.28	13.53
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	28	60	80	112	56	222	43	150	15	43	55	40	11	13
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	105	2,005	8,565	6,427	4,533	7,320	6,643	8,727	0	0	2,424	8,738	8,755	0
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	0	0	79	0	56	0	0	150	0	0	0	40	11.28	0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	(l) 28	60	0	111	56	222	43	150	(m) 15	(n) 49	55	0	0	13
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	(o) 21	52	0	110	56	(p) 0	43	150	(q) 11	(r) 43	55	0	0	13
11	PlantAverageNumberOfEmployees Average Number of Employees	0	7	4	76	5	(s) 0	75	11	0	0	82	(t) 0	(u) 0	0
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	1,533,000	57,077,000	333,060,000	457,543,000	39,925,000	1,667,380,000	203,979,000	408,222,000			93,878,000	120,949,000	39,347,000	(v) 311,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	1,314	36,647		162,629	0	446,126	203,882	1,893,984	13,682			111,793	8,119,540	9,631
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	29,021	10,385,543	14,557,823	9,877,979	0	28,250,520	10,031,491	22,122,874	1,207,604	140,514	7,362,871	29,187,825		348,247
15	CostOfEquipmentSteamProduction Equipment Costs	3,775,985	38,117,227	100,038,361	145,526,392	85,629,725	92,704,447	41,560,520	158,965,842	1,928,823	59,389	55,668,804	53,900,546	11,440,693	7,790,041
16	AssetRetirementCostsSteamProduction Asset Retirement Costs			1,351,541	467,318		19,799,959	1,893,989				302,405	2,913,993	772,822
17	CostOfPlant Total cost (total 13 thru 20)	3,806,320	48,539,416	115,947,725	156,034,318	85,629,725	141,201,052	53,689,882	182,982,700	3,150,109	199,903	63,334,080	86,114,157	20,333,055	8,147,919
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	132.1639	590.5038	1,449.3466	1,270.121	1,463.7560	584.6834	1,177.9263	900.2839	210.0073	4.6565	1,139.9222	2,152.8539	1,802.5758	602.2113
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	619	24,763	234,537	316,570	23,548	51,014	234,987	367,968			184,128	38,404	30,769	596
20	FuelSteamPowerGeneration Fuel	304,962	4,333,665		11,364,984	2,577,688	34,302,960	5,812,863	20,959,550			2,636,255			1,108
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses				464,439		1,438,025	403,066				432,119
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses	15,943	637,491	3,486,109	444,464	606,195	536,048	230,420	3,088,888			2,522	1,891,752	629,327	15,334
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses				596,991		2,379,298	235,812				368,974
27	RentsSteamPowerGeneration Rents							1,567				30,933
28	Allowances Allowances
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	619	24,763		198,119	23,548	521,165	96,277				313,240			596
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures			156,974	174,163		727,635	89,700				76,972	1,130
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant				912,627		4,289,231	1,051,615				564,417
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	58,649	397,905		679,071	90,371	685,934	509,208	1,644,033			135,133	26,095		48,064
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant			14,978	165,707		398,284	152,893				254,486
34	PowerProductionExpensesSteamPower Total Production Expenses	380,792	5,418,587	3,892,598	15,317,134	3,321,350	45,329,594	8,815,273	26,060,439		0	4,999,178	1,957,381	660,096	65,698
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.2484	0.0949	0.0117	0.0335	0.0832	0.0272	0.0432	0.0638	0.0000	0.0000	0.0533	0.0162	0.0168

35	FuelKindAxis Plant Name	Aberdeen #1	Aberdeen #2	Big Stone	Big Stone	Big Stone	Bob Glanzer	Colstrip 4	Colstrip 4	Coyote	Coyote	Coyote	DGGS	DGGS	Huron CT #1	Huron GT #2	Neal	Neal	Yankton
36	FuelKind Fuel Kind	Oil	Gas	Coal	Oil	Other	Gas	Coal	Oil	Coal	Oil	Other	Gas	Oil	Gas	Gas	Coal	Oil	Oil
37	FuelUnit Fuel Unit	bbl	MMBTU	T	bbl	T	MMBTU	T	bbl	T	bbl	T	MMBTU	bbl	MMBTU	MMBTU	T	bbl	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	5,127	718,983	323,734	1,968	767,982	338,394	1,034,456	1,385	181,842	1,217	1,227	4,654,796	7,421		21	60,066	2,749	0
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	138,000	1,000	4,795	140,000	0	1,000	8,597	140,000	6,963	140,000	0	1,000	140,000	1,000	1,000	8,593	139,000	138,000
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	105.633	5.391	31.368	69.817	263.639	7.430	32.984	131.622	30.174	92.621	132.724	4.450	127.970			36.948	136.770
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	105.633	5.391	31.368	69.817	263.639	7.430	32.984	131.622	30.174	92.621	132.724	4.450	127.970			36.948	136.770
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	18.225	5.391	3.271	11.874		257.769	1.918	22.385	2.167	15.752		4.411	21.764			2.150	23.428
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	(w) 0.199	(x) 0.076	(y) 0.025			(z) 0.065	(aa) 0.021		(ab) 0.028				(ac) 0.053			(ad) 0.028
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	(ae) 19,384.004	(af) 12,596.720	(ag) 6,810.332			(ah) 8,475.742	(ai) 10,672.181		(aj) 12,448.856				(ak) 11,509.499			(al) 11,166.788

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: PlantKind

Designed for peak load service.

(b) Concept: PlantKind

Big Stone - Respondent's share is 23.4%. Generation expenses and revenue are shared on ownership basis. This page represents the respondent's share of plant costs, production expenses and other data.

Designed for peak load service.

(d) Concept: PlantKind

We own 30% of Colstrip Unit 4 and have a reciprical sharing agreement with the 30% owner of Colstrip Unit 3 in which we share equally in the ownership benefits and liabilities of each. This page is representative of that agreement.

(e) Concept: PlantKind

Coyote - Respondent's share is 10%. Generation expenses and revenue are shared on ownership basis. This page represents the respondent's share of plant costs, production expenses and other data.

(f) Concept: PlantKind

Designed for regulation service.

(g) Concept: PlantKind

Designed for peak load service.

(h) Concept: PlantKind

Designed for peak load service. This plant was retired in 2019.

(i) Concept: PlantKind

Neal #4 - Respondent's share is 8.681%. Generation expenses and revenue are shared on ownership basis. This page represents the respondent's share of plant costs, production expenses and other data.

(j) Concept: PlantKind

Designed for peak load service.

(k) Concept: InstalledCapacityOfPlant

Total Installed Capacity (Maximum Generation Name Plate Ratings-MW) is 203.25 MW as reported, however because of limitations on the combustion turbines, the maximum installed capacity is 150 MW.

(l) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater

Site 40 F., Base

(m) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater

Site 40 F., Base

(n) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater

Site 40 F., Base

(o) Concept: NetContinuousPlantCapabilityLimitedByCondenserWater

Site 80 F., Base

(p) Concept: NetContinuousPlantCapabilityLimitedByCondenserWater

When Limited by Condensor Water with "No Limitation."

(q) Concept: NetContinuousPlantCapabilityLimitedByCondenserWater

Site 80 F., Base W/EC

(r) Concept: NetContinuousPlantCapabilityLimitedByCondenserWater

Site 40 F., Base

(s) Concept: PlantAverageNumberOfEmployees

All plant employees are employed by the plant operator, Talen Montana, LLC.

(t) Concept: PlantAverageNumberOfEmployees

All employees are contracted through General Electric as plant operator

(u) Concept: PlantAverageNumberOfEmployees

All employees are contracted through General Electric as plant operator

(v) Concept: NetGenerationExcludingPlantUse

Station power use exceeded generation.

(w) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(x) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(y) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(z) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(aa) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(ab) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(ac) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(ad) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(ae) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration