FERC Form

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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 Commission 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, a wholly owned subsidiary of NorthWestern Energy Group, Inc., doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 775,300 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.

Events occurring subsequent to December 31, 2023, have been evaluated as to their potential impact to the Financial Statements through the date of this report.

Holding Company Reorganization

On October 2, 2023, NorthWestern Corporation and NorthWestern Energy Group, Inc. completed a merger transaction pursuant to which NorthWestern Energy Group, Inc. became the holding company parent of NorthWestern Corporation. In this reorganization, shareholders of NorthWestern Corporation (the predecessor publicly held parent company) became shareholders of NorthWestern Energy Group, Inc., maintaining the same number of shares and ownership percentage as held in NorthWestern Corporation immediately prior to the reorganization. NorthWestern Corporation became a wholly-owned subsidiary of NorthWestern Energy Group. The transaction was effected pursuant to a merger pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the shareholders of the constituent corporation. As a result of the reorganization, NorthWestern Energy Group, Inc. became the successor issuer to NorthWestern Corporation pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, and as a result, NorthWestern Energy Group's common stock was deemed registered under Section 12(b) of the Securities Exchange Act of 1934.

Upon the conversion of all issued and outstanding NorthWestern Corporation common stock into common stock of NorthWestern Energy Group, Inc., as described above, the common stock of NorthWestern Corporation ceased to exist. The accounting for this common stock conversion is treated as a retirement of common stock for NorthWestern Corporation as the shares cease to exist. As such, the amounts included in accounts 201 Common stock and 217 Reacquired capital stock were cleared into account 211 Other paid-in capital. Subsequent to the reorganization, NorthWestern Corporation has 100 shares of common stock issued and outstanding, which are held by NorthWestern Energy Group, Inc.

On January 1, 2024, we completed the second and final phase of the holding company reorganization. NorthWestern Corporation contributed the assets and liabilities of its South Dakota and Nebraska regulated utilities to NorthWestern Energy Public Service Corporation, and then distributed its equity interest in NorthWestern Energy Public Service Corporation and certain other subsidiaries to NorthWestern Energy Group, Inc., resulting in NorthWestern Corporation owning and operating the Montana regulated utility and NorthWestern Energy Public Service Corporation owning and operating the Nebraska and South Dakota utilities, each as a direct subsidiary of NorthWestern Energy Group, Inc.


(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 $523.7 million and $502.2 million as of December 31,2023 and December 31,2022, 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 31,2023 and December 31,2022, 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 31,2023 and December 31,2022, 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 $0.9 million and $1.3 million as of December 31,2023 and December 31,2022, 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 $0.9 million and $1.3 million as of December 31,2023 and December 31,2022, 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, 2023 and 2022 (in millions):


	Twelve Months Ended December 31, 2023
	Total		Electric		Natural Gas		Other

GAAP Revenues	$	1,422.1	$	1,068.8	$	353.3	$	—
Revenue from equity investments	(2.9)		—		(2.9)		—
Grossing revenues / power purchases	93.4		93.4		—		—
Regulatory amortizations	135.5		108.6		26.9		—
Other	10.6		11.3		(1.9)		1.2
FERC Revenues	$	1,658.7	$	1,282.1	$	375.4	$	1.2


	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

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 $2.8 million and $2.5 million at December 31, 2023 and December 31, 2022, respectively. Unbilled revenues were $105.1 million and $117.4 million at December 31, 2023 and December 31, 2022, respectively.

Inventories

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


	December 31,
	2023		2022
Fuel stock	$	9,711	$	7,725
Plant materials and operating supplies	85,254		71,154
Gas stored underground (including the non-current portion reflected in utility plant)	55,027		63,933
Total Inventories	$	149,992	$	142,812

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, 2023, 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 is 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% for Montana for 2023 and 2022. This rate averaged 6.4% for South Dakota in 2023 and 2022. AFUDC capitalized totaled $24.3 million and $20.2 million for the years ended December 31, 2023 and 2022, 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 127 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 2023 and 2022.

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 Statements of Income and provision for income taxes.

Under the Inflation Reduction Act of 2022 our production tax credits may be transferred to an unrelated entity. Our policy is to account for these transferable credits within income tax expense.

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,
	2023		2022
	(in thousands)
Cash paid (received) for:
Income taxes	$	(827)	$	4,707
Interest	105,238		95,400
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	42,322		64,758

The following table provides a reconciliation of cash, working 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,
	2023		2022
Cash	$	8,741	$	8,029
Working funds	23		23
Special deposits	14,857		12,762
Total shown in the Statement of Cash Flows	$	23,621	$	20,814

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

There were no accounting standards adopted in the current year that had a material impact to our financial condition, results of operations, and cash flows. 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 under Docket 2022.07.78 requesting an annual increase to electric and natural gas utility rates. On October 27, 2023, the MPSC issued a final order approving the settlement agreement filed April 3, 2023. Final rates, adjusting from interim to settled rates, were effective November 1, 2023. The details of our settlement agreement are set forth below:


Returns, Capital Structure & Revenue Increase Resulting From Approved Settlement Agreement ($ in millions)
	Electric	Natural Gas
Return on Equity (ROE)	9.65%	9.55%
Equity Capital Structure	48.02%	48.02%

Base Rates	$67.4	$14.1
PCCAM(1)	$69.7	n/a
Property Tax (tracker base adjustment)(1)	$14.5	$4.2
Total Revenue Increase Through Approved Settlement Agreement	$151.6	$18.3

(1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.

The approved settlement includes, among other things, agreement on electric and natural gas base revenue increases, allocated cost of service, rate design, updates to the base amount of revenues associated with property taxes and electric supply costs, and regulatory policy issues related to requested changes in regulatory mechanisms.

The approved settlement agreement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. It also addresses the potential for future recovery of certain operating costs associated with the Yellowstone County Generating Station and provides for the deferral of incremental operating costs related to our Enhanced Wildfire Mitigation Plan. The settling parties agreed to terminate the pilot decoupling program (Fixed Cost Recovery Mechanism) and that the proposed business technology rider will not be implemented.

South Dakota Electric Rate Review

On June 15, 2023, we filed a South Dakota electric rate review filing (2022 test year) under Docket EL23-016 for an annual increase to electric rates totaling approximately $30.9 million. Our request was based on a rate of return of 7.54 percent, a capital structure including 50.5 percent equity, and rate base of $787.3 million. On January 10, 2024, the SDPUC issued a final order approving the settlement agreement between NorthWestern and SDPUC Staff for an annual increase in base rates of approximately $21.5 million and an authorized rate of return of 6.81 percent. The approved settlement is based on a capital structure of 50.5 percent equity and a rate base of $791.8 million. Final rates were effective January 10, 2024. In addition, NorthWestern was approved a phase in rate plan rider that allows for the recovery of capital investments not yet included in base rates.


(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,
	2023		2022
Havre Pipeline Company, LLC	$	13,163	$	11,399
NorthWestern Energy Solutions, Inc.	11,797		5,738
Canadian Montana Pipeline Corporation	5,182		4,984
NorthWestern Services, LLC	2,135		2,091
Risk Partners Assurance, Ltd.	1,097		1,132
NorthWestern Energy Public Service Corporation	0		—
Total Investments in Subsidiary Companies	$	33,374	$	25,344


(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 are the only items earning a rate of return. These 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,
			2023		2022
			(in thousands)
Flow-through income taxes	14	Plant Lives	$	553,452	$	509,038
Pension	16	See Note 16	79,638		87,965
Excess deferred income taxes	14	Plant Lives	51,404		54,364
Employee related benefits	16	See Note 16	21,926		27,920
State & local taxes & fees		1 Year	2,733		15,643
Environmental clean-up	19	Undetermined	11,131		10,963
Other		Various	25,741		23,191
Total Regulatory Assets			$	746,025	$	729,084
Excess deferred income taxes	14	Plant Lives	136,382		148,989
Unbilled revenue		1 Year	16,004		11,536
Gas storage sales		17 years	6,625		7,046
State & local taxes & fees		1 Year	30,576		2,327
Environmental clean-up and other		1 Year	1,059		1,503
Total Regulatory Liabilities			$	190,646	$	171,401

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 and postretirement benefit 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.

Enhanced Wildfire Mitigation Plan

We have developed an Enhanced Wildfire Mitigation Plan addressing five key areas: situational awareness, operational practices, system preparedness, vegetation management, and public communications outreach. Because of ever-increasing wildfire risk, our plan includes greater focus on situational awareness to monitor changing environmental conditions, operational practices that are more reactive to changing conditions, increased frequency of patrol and repairs, and more robust system hardening programs that target higher risk segments in our transmission and distribution systems. As discussed within Note 3 - Regulatory Matters, the approved Montana rate review settlement provides for the deferral of incremental operating costs related to this Enhanced Wildfire Mitigation Plan. As of December 31, 2023, we have deferred $1.6 million of incremental costs as a regulatory asset related to this plan for future recovery.

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,
	2023		2022
	(in thousands)
Electric Plant	$	5,543,091	$	5,286,650
Natural Gas Plant	1,446,664		1,311,436
Plant acquisition adjustment	686,328		686,328
Common and Other Plant	307,030		306,866
Construction work in process	358,401		300,649
Total utility plant	8,341,514		7,891,929
Less accumulated depreciation	(2,874,902)		(2,786,712)
Net utility plant	$	5,466,612	$	5,105,217

Net utility plant under capital (finance) lease were $5.2 million and $7.2 million as of December 31, 2023 and 2022, respectively, which included $5.0 million and $7.0 million as of December 31, 2023 and 2022, 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.

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 31,2023
Ownership percentages	23.4		%	8.7		%	10.0		%	30.0		%
Plant in service	$	156,696		$	64,132		$	52,630		$	323,793
Accumulated depreciation	48,537			40,528			42,942			128,484
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


(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,
	2023		2022
Liability at January 1,	$	40,894	$	40,631
Accretion expense	1,899		1,853
Liabilities incurred	—		—
Liabilities settled	(1,244)		(4,004)
Revisions to cash flows	(125)		2,414
Liability at December 31,	$	41,424	$	40,894

During the twelve months ended December 31, 2023 our ARO liability decreased $1.2 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, 2023, our ARO liability decreased $0.1 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 adjustment impairment test as of April 1, 2023. We evaluated qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors, and overall financial performance) to determine whether it was more likely than not that the fair value of our reporting units were less than their carrying amounts. Our evaluation of these factors concluded that it was not more likely than not that the fair value of our reporting units was less than their carrying amounts and therefore no further testing was necessary.


(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, 2023 and 2022. 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 $12.8 million is remaining in AOCI as of December 31, 2023, 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 31,2023	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	$	14,857	$	—	$	—	$	—	$	14,857
Rabbi trust investments	17,093		—		—		—		17,093
Total	$	31,950	$	—	$	—	$	—	$	31,950

December 31,2022
Special deposits	$	12,762	$	—	$	—	$	—	$	12,762
Rabbi trust investments	20,895		—		—		—		20,895
Total	$	33,657	$	—	$	—	$	—	$	33,657

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 31,2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	2,797,660	$	2,534,105	$	2,629,660	$	2,327,478

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 November 29, 2023, NorthWestern Corporation amended its existing $425.0 million revolving credit facility (the Amended Facility) to address the holding company reorganization and extended the maturity date of the facility to November 29, 2028. The Amended 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. After the completion of the holding company reorganization on January 1, 2024, NorthWestern Corporation owns and operates only the Montana regulated utility, and the base capacity of the Amended Facility automatically reduced to $400.0 million.

On October 28, 2022, we entered into a $100.0 million Credit Agreement (the Additional Credit Facility) to supplement our existing $425.0 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. As of December 31, 2023, there were no amounts outstanding under this Additional Credit Facility.

On March 25, 2023, we amended our existing $25.0 million swingline credit facility (the Swingline Facility) to extend the maturity date of the facility from March 27, 2024 to March 27, 2025. 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. As of December 31, 2023, there were no amounts outstanding under this Swingline Facility.

On January 2, 2024, NorthWestern Corporation terminated its $100.0 million Additional Credit Facility. On January 4, 2024, NorthWestern Corporation terminated its $25.0 million Swingline Facility.

Commitment fees for the unsecured revolving lines of credit were $0.6 million and $0.1 million for the years ended December 31, 2023 and 2022.

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


	2023		2022
Unsecured revolving line of credit, expiring May 2027	$	—	$	425.0
Unsecured revolving line of credit, expiring November 2028(1)	425.0		—
Unsecured revolving line of credit, expiring April 2024(2)	100.0		100.0
Unsecured revolving line of credit, expiring March 2025(2)	25.0		25.0
	550.0		550.0

Amounts outstanding at December 31:
SOFR borrowings	318.0		450.0
Letters of credit	—		—
	318.0		450.0

Net availability as of December 31	$	232.0	$	100.0

(1) Upon the completion of the holding company reorganization on January 1, 2024, the base capacity of this facility decreased to $400.0 million.

(2) NorthWestern Corporation terminated the $100.0 million Additional Credit Facility on January 2, 2024, and the $25.0 million Swingline Facility on January 4, 2024.

Our credit facilities include covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facilities also contain 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 Montana First Mortgage Bonds would trigger a cross default on the Amended Facility; however, a default on the Amended Facility would not trigger a default on the Montana First Mortgage Bonds.


(12)Long-Term Debt

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


		December 31,
	Due	2023		2022
Unsecured Debt:
Unsecured Revolving Line of Credit	2027	$	—	$	425,000
Unsecured Revolving Line of Credit	2028	318,000		—
Unsecured Revolving Line of Credit	2024	—		25,000
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
South Dakota—5.57%	2033	31,000		—
South Dakota—5.42%	2033	30,000		—
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
Montana—5.57%	2033	239,000		—
Pollution control obligations—
Montana—2.00%	2023	—		144,660
Montana—3.88%	2028	144,660		—
Total Long-Term Debt		$	2,797,660	$	2,629,660

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 South Dakota indenture was transferred from NorthWestern Corporation to NorthWestern Energy Public Service Corporation upon the completion of the holding company reorganization on January 1, 2024.

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

On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On May 1, 2023, we issued and sold an additional $30 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent maturing on May 1, 2033. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes.

On June 29, 2023, the City of Forsyth, Rosebud County, Montana issued $144.7 million principal amount of Pollution Control Revenue Refunding Bonds (2023 Pollution Control Bonds) on our behalf. The 2023 Pollution Control Bonds were issued at a fixed interest rate of 3.88 percent maturing on July 1, 2028. The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and were deposited directly with U.S. Bank Trust Company, National Association, as trustee, for the redemption of the 2.00 percent, $144.7 million City of Forsyth Pollution Control Revenue Refunding Bonds due on August 1, 2023 that had previously been issued on our behalf. Pursuant to the Loan Agreement, we are obligated to make payments in such amounts and at such times as will be sufficient to pay, when due, the principal and interest on the 2023 Pollution Control Bonds. Our obligations under the Loan Agreement are secured by delivery of a like amount of our Montana First Mortgage Bonds, which are secured by our Montana electric and natural gas assets. So long as we are making payments under the Loan Agreement, no payments under these mortgage bonds will be due. The 2023 Pollution Control Bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

As of December 31, 2023, we were in compliance with our financial debt covenants.

Maturities of Long-Term Debt

The aggregate minimum principal maturities of long-term debt during the next five years are $100.0 million in 2024, $300.0 million in 2025, $105.0 million in 2026, and $497.7 million in 2028.


(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,
	2023		2022
Accounts Receivable from Associated Companies:
Havre Pipeline Company, LLC	$	591	$	3,201
NorthWestern Energy Solutions, Inc.	112		16
Risk Partners Assurance, Ltd.	(88)		(74)
	$	615	$	3,143

Accounts Payable to Associated Companies:
Canadian Montana Pipeline Corporation	$	2,516	$	2,312
NorthWestern Services, LLC	2,082		2,045
NorthWestern Energy Group, Inc.	206		—
	$	4,804	$	4,357


(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, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable), and production tax credits. 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 liability recognized in our Balance Sheets are related to the following temporary differences (in thousands):


	December 31,
	2023		2022
NOL Carryforward	$	113,310	$	—
Production tax credit	94,283		80,097
Pension / postretirement benefits	15,131		19,291
Customer advances	28,300		25,119
Unbilled revenue	10,604		9,440
Compensation accruals	10,716		10,306
Environmental liability	5,760		6,009
Interest rate hedges	3,280		3,372
Reserves and accruals	3,098		4,015
Other, net	5,401		6,295
Deferred Tax Asset	289,883		163,944
Excess tax depreciation	(663,638)		(455,220)
Flow through depreciation	(119,458)		(104,976)
Goodwill amortization	(91,803)		(91,746)
Regulatory assets and other	(20,246)		(58,065)
Deferred Tax Liability	(895,145)		(710,007)
Deferred Tax Liability, net	$	(605,262)	$	(546,063)

As of December 31, 2023, our total federal NOL carryforward was approximately $447.8 million. Our federal NOL carryforward does not expire. Our state NOL carryforward as of December 31, 2023 was approximately $362.1 million. If unused, our state NOL carryforwards will expire in 2033. We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards.

At December 31, 2023, our total production tax credit carryforward was approximately $94.3 million. If unused, our production tax credit carryforwards will expire as follows: $1.8 million in 2035, $10.9 million in 2036, $11.1 million in 2037, $10.9 million in 2038, $11.5 million in 2039, $13.1 million in 2040, $11.5 million in 2041, $13.2 million in 2042, and $10.4 million in 2043. 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):


	2023		2022
Unrecognized Tax Benefits at January 1	$	30,330	$	32,049
Gross increases - tax positions in prior period	—		—
Gross increases - tax positions in current period	—		—
Gross decreases - tax positions in current period	(2,256)		(1,719)
Lapse of statute of limitations	—		—
Unrecognized Tax Benefits at December 31	$	28,074	$	30,330

Our unrecognized tax benefits include approximately $24.4 million and $27.9 million related to tax positions as of December 31, 2023 and 2022, that if recognized, would impact our annual effective tax rate. On April 14, 2023, the Internal Revenue Service (IRS) issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. During the year ended December 31, 2023, we adopted this method and decreased our total unrecognized tax benefits by $0.5 million and recognized an income tax benefit of approximately $3.2 million for previously unrecognized tax benefits. In the next twelve months we expect the statute of limitations to expire for certain uncertain tax benefits, which would result in a decrease to our total unrecognized tax benefits of approximately $16.9 million.

Our policy is to recognize interest related to uncertain tax positions in interest expense. As of December 31, 2023, we have accrued $4.5 million for the payment of interest in the Balance Sheets. As of December 31, 2022, we had $1.4 million accrued for the payment of interest.

Tax years 2020 and forward remain subject to examination by the IRS and state taxing authorities. During the first quarter of 2023 the IRS commenced and concluded a limited scope examination of our 2019 amended federal income tax return. This examination resulted in a reduction to our previously claimed alternative minimum tax credit refund that is reflected in the table above.


(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,
	2023						2022
	Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount		Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount
Foreign currency translation adjustment	$	2	$	—	$	2	$	(8)	$	—	$	(8)
Reclassification of net income (loss) on derivative instruments	612		(160)		452		612		(160)		452
Postretirement medical liability adjustment	(330)		69		(261)		(1,359)		377		(982)
Other comprehensive income (loss)	$	284	$	(91)	$	193	$	(755)	$	217	$	(538)

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


	December 31,
	2023		2022
Foreign currency translation	$	1,437	$	1,435
Derivative instruments designated as cash flow hedges	(7,223)		(7,675)
Postretirement medical plans	273		534
Accumulated other comprehensive loss	$	(5,513)	$	(5,706)

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


	December 31,2023
	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		$	(7,675)	$	534	$	1,435	$	(5,706)
Other comprehensive income before reclassifications						2		2
Amounts reclassified from AOCI	Interest on long-term debt	452						452
Amounts reclassified from AOCI				(261)				(261)
Net current-period other comprehensive income		452		(261)		2		193
Ending Balance		$	(7,223)	$	273	$	1,437	$	(5,513)


	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)


(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, 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,
	2023		2022		2023		2022
Change in benefit obligation:
Obligation at beginning of period	$	521,798	$	696,802	$	15,407	$	17,308
Service cost	5,646		10,223		333		351
Interest cost	25,852		18,787		674		358
Actuarial loss	3,127		(176,389)		(1,240)		(99)
Settlements(1)	(51,942)		—		—		—
Benefits paid	(30,493)		(27,625)		(1,466)		(2,511)
Benefit Obligation at End of Period	$	473,988	$	521,798	$	13,708	$	15,407
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	$	441,539	$	605,499	$	20,055	$	25,289
Return on plan assets	34,367		(144,535)		3,334		(4,098)
Employer contributions	9,200		8,200		386		1,375
Settlements(1)	(51,942)		—		—		—
Benefits paid	(30,493)		(27,625)		(1,466)		(2,511)
Fair value of plan assets at end of period	$	402,671	$	441,539	$	22,309	$	20,055
Funded Status	$	(71,317)	$	(80,259)	$	8,601	$	4,648

Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	7,875		7,195		12,378		8,831
Total Assets	7,875		7,195		12,378		8,831
Current liability	(11,200)		(11,200)		(1,355)		(1,585)
Noncurrent liability	(67,992)		(76,254)		(2,422)		(2,598)
Total Liabilities	(79,192)		(87,454)		(3,777)		(4,183)
Net amount recognized	$	(71,317)	$	(80,259)	$	8,601	$	4,648

Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	—		—		—		(116)
Net actuarial loss	(44,453)		(54,383)		15		(3,123)
Amounts recognized in AOCI consist of:
Prior service cost	—		—		—		—
Net actuarial gain	—		—		590		1,046
Total	$	(44,453)	$	(54,383)	$	605	$	(2,193)

(1) In October 2023, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 285 NorthWestern Energy Pension Plan participants. We purchased the contract with $51.9 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2024. This transaction settled $51.9 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2023, we recorded a non-cash, non-operating settlement charge of $4.4 million. This charge is recorded within operating expense, net on the Statements of Income. As discussed within Note 5 – Regulatory Assets and Liabilities, the MPSC allows recovery of pension costs on a cash funding basis. As such, 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,
	2023		2022
Projected benefit obligation	$	427.3	$	474.9
Accumulated benefit obligation	427.3		474.9
Fair value of plan assets	348.1		388.7

_____________________

As of December 31, 2023, 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,
	2023		2022		2023		2022
Components of Net Periodic Benefit Cost
Service cost	$	5,646	$	10,223	$	333	$	351
Interest cost	25,852		18,787		674		359
Expected return on plan assets	(25,932)		(24,173)		(1,096)		(1,047)
Amortization of prior service cost (credit)	—		—		116		(1,891)
Recognized actuarial loss (gain)	228		383		(672)		(897)
Settlement loss recognized(1)	4,395		—		—		—
Net Periodic Benefit Cost (Credit)	$	10,189	$	5,220	$	(645)	$	(3,125)

Regulatory deferral of net periodic benefit cost(2)	(1,814)		2,307		—		—
Previously deferred costs recognized(2)	210		—		550		292
Amount Recognized in Income	$	8,585	$	7,527	$	(95)	$	(2,833)

_________________________

(1) Settlement losses are related to partial annuitization of NorthWestern Energy Pension Plan effective October 24, 2023 and December 1, 2021, respectively.

(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 the years ended December 31, 2023 and 2022, Service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income, net on the Statements of Income.

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, 2023 and 2022. 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 decrease in the discount rate during 2023 increased our projected benefit obligation by approximately $10.5 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 6.65 percent and increased our assumption on the NorthWestern Corporation Pension Plan to 5.15 percent for 2024.

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


	Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,
	2023		2022		2023		2022
Discount rate	4.95-5.00	%	5.20	%	4.85-4.90	%	5.15-5.20	%
Expected rate of return on assets	4.83-6.44		2.66-4.26		5.62		4.23
Long-term rate of increase in compensation levels (non-union)	4.00		4.00		4.00		4.00
Long-term rate of increase in compensation levels (union)	4.00		4.00		4.00		4.00
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,
	2023		2022		2023		2022		2023		2022
Fixed income securities	45.0	%	45.0	%	90.0	%	90.0	%	40.0	%	40.0	%
Non-U.S. fixed income securities	—		—		—		1.0		—		—
Opportunistic fixed income	11.0		5.5		3.0		—		—		—
Global equities	38.5		44.0		7.0		9.0		60.0		60.0
Private real estate	5.5		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,
	2023		2022		2023		2022		2023		2022
Cash and cash equivalents	—	%	—	%	1.5	%	1.1	%	0.2	%	0.6	%
Fixed income securities	45.3		44.5		88.7		88.6		35.1		36.7
Non-U.S. fixed income securities	—		—		—		0.9		—		—
Opportunistic fixed income	10.6		5.5		2.9		—		—		—
Global equities	37.6		43.4		6.9		9.4		64.7		62.7
Private real estate	6.5	%	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 Energy Group 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 2024 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 2023 and 2022 were based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands):


	2023		2022
NorthWestern Energy Pension Plan (MT)	$	8,000	$	7,000
NorthWestern Corporation Pension Plan (SD and NE)	1,200		1,200
	$	9,200	$	8,200

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


	Pension Benefits		Other Postretirement Benefits
2024	$	27,553	$	2,149
2025	28,987		1,813
2026	29,920		1,406
2027	30,545		1,251
2028	31,231		1,210
2029-2032	164,362		5,288

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, 2023 and 2022 were $13.2 million and $12.3 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. These stock-based awards are for the common stock of NorthWestern Energy Group, Inc. As part of effectuating the holding company reorganization, all outstanding and unexercised, unvested and not yet paid or payable stock-based awards were converted into a right to acquire NorthWestern Energy Group, Inc. capital stock of the same class and with the same rights and privileges relative to the stock-based award prior to the merger. See Note 1 - Nature of Operations for further information regarding the holding company effectuation in 2023.

As of December 31, 2023, there were 649,884 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to four 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. Beginning in 2023, these awards contain service-, market-, and performance-based components. The service-based component of these awards, representing 30 percent of the award, vest at the end of the three-year performance period as long as the individual has remained employed with us over that term. The performance goals are independent of each other and equally weighted at 35 percent of the award, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return relative to a peer group. Performance unit awards issued prior to 2023 included both the market- and performance-based components discussed above.

Fair value is determined for each component of the performance unit awards. The fair value of the service-based component is estimated based upon the closing market price of our common stock as of the grant date less the present value of expected dividends. The fair value of the performance-based component is estimated based upon the closing market price of our common stock as of the grant date 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 market-based component 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:


	2023		2022
Risk-free interest rate	4.33	%	1.82	%
Expected life, in years	3		3
Expected volatility	30.4% to 41.0%		28.2% to 38.8%
Dividend yield	4.4	%	4.5	%

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, 2023, are as follows:


	Performance Unit Awards
	Shares	Weighted-Average Grant-Date Fair Value
Beginning nonvested grants	194,407	$	51.04
Granted	95,853	54.41
Vested	(87,300)	50.53
Forfeited	(49,176)	51.59
Remaining nonvested grants	153,784	$	53.26

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 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. No retirement/retention restricted shares were granted during the year ended December 31, 2023. 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 grant date less the present value of expected dividends.

A summary of nonvested shares as of and changes during the year ended December 31, 2023, are as follows:


	Shares	Weighted-Average Grant-Date Fair Value
Beginning nonvested grants	99,285	$	48.62
Granted	—	—
Vested	—	—
Forfeited	(38,506)	49.73
Remaining nonvested grants	60,779	$	47.91

We recognized total stock-based compensation expense of $3.6 million and $4.2 million for the years ended December 31, 2023 and 2022, respectively, and related income tax benefit of $(1.0) million and $(1.3) million for the years ended December 31, 2023 and 2022, respectively. As of December 31, 2023, we had $6.5 million of unrecognized compensation cost related to the nonvested portion of our outstanding awards. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $4.4 million and $4.3 million for the years ended December 31, 2023 and 2022, respectively.


(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.

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 4,167 and 16,120 during the years ended December 31, 2023 and 2022, 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, NorthWestern Corporation entered into an Equity Distribution Agreement pursuant to which we could 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. During the twelve months ended December 31, 2023, NorthWestern Corporation issued 1,432,738 shares of our common stock under the ATM program at an average price of $52.02, for net proceeds of $73.6 million, which is net of sales commissions and other fees paid of approximately $0.9 million. We have completed the ATM offering program under this Equity Distribution 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 $67 to $136 per MWH through 2029. As of December 31, 2023, our estimated gross contractual obligation related to these contracts was approximately $303.1 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $266.5 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,
	2023		2022
Beginning QF liability	$	49,728	$	64,943
Settlements(1)	(24,707)		(20,076)
Interest on long-term debt	3,649		4,861
Ending QF liability	$	28,670	$	49,728

______________________

(1) The primary components of the change in settlement amounts includes (i) a lower periodic adjustment of $4.2 million due to actual price escalation, which was less than previously modeled; and (ii) higher costs of approximately $1.0 million, due to a $0.8 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $1.8 million reduction in costs in the prior period.

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


	Gross Obligation		Recoverable Amounts		Net
2023	$	74,110	$	60,706	$	13,404
2024	60,360		52,950		7,410
2025	55,393		46,274		9,119
2026	56,665		46,668		9,997
2027	42,400		41,664		736
Thereafter	14,134		18,231		(4,097)
Total(1)	$	303,062	$	266,493	$	36,569

_____________________

(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 expense in the Statements of Income and were approximately $340.0 million and $328.0 million for the years ended December 31, 2023 and 2022, respectively. As of December 31, 2023, our commitments under these contracts were $321.9 million in 2024, $244.1 million in 2025, $263.4 million in 2026, $243.6 million in 2027, $225.9 million in 2028, 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 $22.4 million between 2024 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 $21.0 million to $31.4 million. As of December 31, 2023, we had a reserve of approximately $25.3 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,
	2023		2022
Liability at January 1,	$	26,367	$	26,866
Deductions	(2,520)		(2,033)
Charged to costs and expense	1,439		1,534
Liability at December 31,	$	25,285	$	26,367

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 $19.8 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, 2023, the reserve for remediation costs at this site was approximately $8.0 million, and we estimate that approximately $2.9 million of this amount will be incurred through 2028.

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 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 in March 2022 and are awaiting its review and comments as to any additional field work. We now expect the MDEQ review of the RI Report to be concluded in 2024, 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 emissions. Coal-fired plants have come under particular scrutiny due to their level of emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

Proposed EPA Rules - Congress has not passed any federal climate change legislation regarding GHG emissions from coal fired plants, and we cannot predict the timing or form of any potential legislation. 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. In May 2023, EPA proposed new GHG emissions standards for coal and natural gas-fired plants. In particular, the proposed rules would (i) strengthen the current New Source Performance Standards for newly built fossil fuel-fired stationary combustion turbines (generally natural gas-fired); (ii) establish emission guidelines for states to follow in limiting carbon pollution from existing fossil fuel-fired steam generating electric generating units (including coal, oil and natural gas-fired units); and (iii) establish emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired). In addition, in April 2023, EPA proposed to amend the MATS. Among other things, MATS currently sets stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. We are in compliance with existing MATS requirements. The proposed amendment of the MATS would strengthen the MATS requirements, and if adopted as written, both the GHG and MATS proposed rules could have a material negative impact on our coal-fired plants, including requiring potentially expensive upgrades or the early retirement of Colstrip Unit's 3 and 4 due to the rules making the facility uneconomic.

Previous efforts by the EPA were met with extensive litigation and we anticipate a similar response if the proposed rules are adopted. As MATS and GHG regulations are implemented, it could result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any MATS or GHG regulations that, in our view, disproportionately impact customers in our region.

Future additional environmental requirements - federal or state - 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 or hazardous air pollutants may not be available within a timeframe consistent with the implementation of any such 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

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 Montana, LLC (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 navigability of the riverbeds associated with four of our hydroelectric facilities near Great Falls. A bench trial before the Federal District Court commenced January 4, 2022, and concluded on January 18, 2022, which addressed the issue of navigability concerning our other six facilities. On August 25, 2023, the Federal District Court issued its Findings of Fact, Conclusions of Law and Order (the "Order"), which found all but one of the segments of the riverbeds in dispute not navigable, and thus not owned by the State of Montana. The one segment found navigable, and thus owned by the State, was the segment on which the Black Eagle development was located. The State filed a motion to pursue an interlocutory appeal of the Order, and on January 2, 2024, the Federal District Court certified the Order for appeal to the 9th Circuit Court of Appeals. Damages were bifurcated by agreement and will be tried separately for the Black Eagle segment, and any other segments found navigable should an appeal be granted and other segments found navigable.

We dispute the State’s claims and intend to continue to vigorously defend the lawsuit. If the Federal District Court calculates damages as the State District Court did in 2008, we do not anticipate the resulting annual rent for the Black Eagle segment would have a material impact to our financial position or results of operations. 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

The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. The six owners of Colstrip Units 3 and 4 currently share the operating costs pursuant to the terms of an Ownership and Operation Agreement (O&O Agreement). However, several of the owners are mandated by Washington and Oregon law to eliminate coal-fired resources in 2025 and 2029, respectively.

As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. The owners previously initiated efforts to identify arbitrators and have agreed to stay the Arbitration through March 31, 2024, while they explore a potential resolution to their disagreements.

Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. 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, 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.

Since this lawsuit remains in its discovery stages, we are unable to predict outcomes. We continue to evaluate 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.

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. NorthWestern and BNSF have settled the majority of the dispute for a non-material sum. Any potential remaining claims are not expected to be material.

Yellowstone County Generating Station Air Permit

On October 21, 2021, the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State District Court, against the MDEQ and NorthWestern, alleging that the environmental analysis conducted by MDEQ prior to issuance of the Yellowstone County Generating Station's air quality construction permit was inadequate. On April 4, 2023, the Montana District Court issued an order finding MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases and remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we paused construction. On June 8, 2023, the Montana District Court granted our motion to stay the order vacating the air quality permit pending the outcome of our notice of appeal with the Montana Supreme Court. Oral argument is scheduled for April 22, 2024 and a determination of the appeal will follow. We recommenced construction in June 2023 and expect the plant to be operational no later than the end of the third quarter 2024. The ultimate resolution of the lawsuit challenging the Yellowstone County Generating Station air quality permit could delay the project and increase costs.

During the litigation of the air permit, Montana House Bill 971 was signed into law, preventing the MDEQ from, except under certain exceptions, evaluating greenhouse gas emissions and corresponding impacts to the climate in environmental reviews of large projects such as coal mines and power plants. On June 1, 2023, the MDEQ issued its supplemental environmental assessment that contained the updated exterior lighting analysis, and the MDEQ indicated that no other analysis was necessary. The comment period concerning the MDEQ’s supplemental air quality permit ended on July 3, 2023. On August 4, 2023, the Montana First Judicial District Court in Held v. State of Montana, a separate case by Montana youths alleging climate damages, issued its order finding House Bill 971 unconstitutional delaying the issuance of the revised Yellowstone County Generating Station's air permit. The Montana Supreme Court granted NorthWestern permission to participate in the Held appeal. The outcome of the Held case could pose additional delays and costs for the Yellowstone County Generating Station.

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:

12/31/2023

Year/Period of Report

End of:

2023

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		1,518,461		1,441,981	8,128,038		5,167,596
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income		(a) 982,991			(e) 452,130		530,861
3	Preceding Quarter/Year to Date Changes in Fair Value				(c) 7,207			7,207
4	Total (lines 2 and 3)		982,991		7,207	452,130		538,068	183,006,620	182,468,552
5	Balance of Account 219 at End of Preceding Quarter/Year		535,470		1,434,774	7,675,908		5,705,664
6	Balance of Account 219 at Beginning of Current Year		535,470		1,434,774	7,675,908		5,705,664
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income		(b) 261,851			(f) 452,130		190,279
8	Current Quarter/Year to Date Changes in Fair Value				(d) 2,385			2,385
9	Total (lines 7 and 8)		261,851		2,385	452,130		192,664	194,131,555	194,324,219
10	Balance of Account 219 at End of Current Quarter/Year		273,619		1,437,159	7,223,778		5,513,000

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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)	7,246,717,986	5,534,182,214	1,446,633,922	(d) 1,547,776			264,354,074
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	41,127,257				(e) 40,209,537	(f) 917,720
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified	4,798,750	4,798,750
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	7,292,643,993	5,538,980,964	1,446,633,922	1,547,776	40,209,537	917,720	264,354,074
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	4,140,227	4,110,361	29,866
11	ConstructionWorkInProgress Construction Work in Progress	358,401,452	314,784,647	31,789,634				11,827,171
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	686,328,435	(a) 686,328,435
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	8,341,514,107	6,544,204,407	1,478,453,422	1,547,776	40,209,537	917,720	276,181,245
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,874,902,417	2,206,158,106	557,399,271	1,127,274	35,183,325		75,034,441
15	UtilityPlantNet Net Utility Plant (13 less 14)	5,466,611,690	4,338,046,301	921,054,151	420,502	5,026,212	917,720	201,146,804
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,579,322,998	1,990,020,890	498,438,283	1,127,274	35,183,325		54,553,226
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights	51,927,733		51,927,733
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	54,788,147	(b) 27,273,677	7,033,255				20,481,215
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,686,038,878	2,017,294,567	557,399,271	1,127,274	35,183,325		75,034,441
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	188,863,539	(c) 188,863,539
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,874,902,417	2,206,158,106	557,399,271	1,127,274	35,183,325		75,034,441

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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 $270,599 and $2,387 for 2023 and 2022, respectively.

Amortization of Other Montana Electric Plant was $27,003,078 and $24,207,683 for 2023 and 2022, respectively.

Amortization of Plant Acquisition Adjustments of $188,863,539 consist of $178,960,291 for Montana Operations and $9,903,248 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:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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) 20,247,608	1,232,101				21,479,709
4	(303) Miscellaneous Intangible Plant	12,251,711	3,658,800			2,662,554	18,573,065
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	32,519,314	4,890,901			2,662,554	40,072,769
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	812,637					812,637
9	(311) Structures and Improvements	55,522,863	488,271	55,381			55,955,753
10	(312) Boiler Plant Equipment	244,887,717	1,615,237	2,633,055			243,869,899
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	48,867,033	1,094,959	1,250,032			48,711,960
13	(315) Accessory Electric Equipment	15,657,364	36,622	472,785			15,221,201
14	(316) Misc. Power Plant Equipment	26,048,047	219,867	35,757			26,232,157
15	(317) Asset Retirement Costs for Steam Production	22,463,670	913,721				23,377,391
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	414,259,331	4,368,677	4,447,010			414,180,998
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	5,941,678	16,738				5,958,416
29	(332) Reservoirs, Dams, and Waterways	126,687,963	3,404,837	42,238			130,050,562
30	(333) Water Wheels, Turbines, and Generators	195,625,955	15,693,790	16,157,945			195,161,800
31	(334) Accessory Electric Equipment	176,785,446	13,493,970	713,244			189,566,172
32	(335) Misc. Power Plant Equipment	94,377,564	490,305				94,867,869
33	(336) Roads, Railroads, and Bridges	20,725,764	42,624				20,768,388
34	(337) Asset Retirement Costs for Hydraulic Production	2,947,096	122,188				3,069,284
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	623,091,466	33,264,452	16,913,427			639,442,491
36	D. Other Production Plant
37	(340) Land and Land Rights	3,901,868	178,696				4,080,564
38	(341) Structures and Improvements	86,250,639	305	617,605			85,633,339
39	(342) Fuel Holders, Products, and Accessories	26,534,378		20,580			26,513,798
40	(343) Prime Movers	230,850,977	21,003,307	33,810,850			218,043,434
41	(344) Generators	143,520,064					143,520,064
42	(345) Accessory Electric Equipment	27,080,006		55,169			27,024,837
43	(346) Misc. Power Plant Equipment	51,794,908	41,710	130,597			51,706,021
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)	574,971,196	21,224,018	34,634,801			561,560,413
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	1,612,321,993	58,857,147	55,995,238			1,615,183,902
47	3. Transmission Plant
48	(350) Land and Land Rights	41,854,653	2,986,050				44,840,703
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	61,332,819	11,972,290	423,877		4,266,936	77,148,168
50	(353) Station Equipment	440,406,499	46,051,449	7,741,360		4,067,306	474,649,282
51	(354) Towers and Fixtures	30,385,864	254,278				30,640,142
52	(355) Poles and Fixtures	519,110,409	40,943,138	2,096,507		76,600	557,880,440
53	(356) Overhead Conductors and Devices	212,937,523	6,421,698	433,279		7,211	218,933,153
54	(357) Underground Conduit	778,680					778,680
55	(358) Underground Conductors and Devices	6,640,975	1,384			26,615	6,668,974
56	(359) Roads and Trails	4,043,372					4,043,372
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	1,317,490,794	108,630,287	10,695,023		156,856	1,415,582,914
59	4. Distribution Plant
60	(360) Land and Land Rights	15,371,502	51,702	4,106			15,419,098
61	(361) Structures and Improvements	39,975,630	3,479,455	368,182		2,626,241	45,713,144
62	(362) Station Equipment	293,557,260	26,178,151	5,315,008		2,883,909	311,536,494
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	431,334,582	21,677,454	1,486,918		90,886	451,616,004
65	(365) Overhead Conductors and Devices	172,262,323	7,696,009	328,759			179,629,573
66	(366) Underground Conduit	179,237,133	14,864,225	62,731			194,038,627
67	(367) Underground Conductors and Devices	328,626,662	20,217,421	831,739			348,012,344
68	(368) Line Transformers	301,713,243	24,026,371	2,216,133			323,523,481
69	(369) Services	196,311,139	13,995,005	279,041			210,027,103
70	(370) Meters	90,993,396	17,724,773	6,995,635			101,722,534
71	(371) Installations on Customer Premises	746,087	10,915	21,640			735,362
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	91,192,236	4,941,140	2,124,970			94,008,406
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,141,321,193	154,862,621	20,034,862		166,782	2,275,982,170
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		1,320			795,141
87	(390) Structures and Improvements	12,542,442	35,793	118,099			12,460,136
88	(391) Office Furniture and Equipment	1,216,438	1,743,075	407,757			2,551,756
89	(392) Transportation Equipment	82,820,012	5,317,518	3,027,609			85,109,921
90	(393) Stores Equipment	1,143,158	48,010				1,191,168
91	(394) Tools, Shop and Garage Equipment	12,583,614	841,767	238,440			13,186,941
92	(395) Laboratory Equipment	1,033,178					1,033,178
93	(396) Power Operated Equipment	7,391,873	655,874	67,546			7,980,201
94	(397) Communication Equipment	52,805,248	9,121,036	1,013,516		16,538	60,929,306
95	(398) Miscellaneous Equipment	2,122,711					2,122,711
96	SUBTOTAL (Enter Total of lines 86 thru 95)	174,455,135	17,763,073	4,874,287		16,538	187,360,459
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)	174,455,135	17,763,073	4,874,287		16,538	187,360,459
100	TOTAL (Accounts 101 and 106)	5,278,108,429	345,004,029	91,599,410		2,669,166	5,534,182,214
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified	4,244,173	554,577				4,798,750
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	5,282,352,602	345,558,606	91,599,410		2,669,166	5,538,980,964

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	20,247,608	1,232,101	—	—	—	21,479,709
4	(303) Miscellaneous Intangible Plant	12,243,407	3,658,800		—	705,518	16,607,725
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and4)	32,511,010	4,890,901	—	—	705,518	38,107,429
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	446,126	—	—	—	—	446,126
9	(311) Structures and Improvements	28,250,520	4,061	40,633	—	—	28,213,948
10	(312) Boiler Plant Equipment	44,982,542	27,910	2,418,216	—	—	42,592,236
11	(313) Engines and Engine-Driven Generators	—	—	—	—	—	—
12	(314) Turbogenerator Units	22,255,086	—	1,185,625	—	—	21,069,461
13	(315) Accessory Electric Equipment	2,519,145	23,075	465,747	—	—	2,076,473
14	(316) Misc. Power Plant Equipment	22,947,674	—	—	—	—	22,947,674
15	(317) Asset Retirement Costs for Steam	19,799,959	1,553,530	—	—	—	21,353,489
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)	141,201,052	1,608,576	4,110,221	—	—	138,699,407
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	5,941,678	16,738	—	—	—	5,958,416
27	(331) Structures and Improvements	126,687,963	3,404,837	42,238	—	—	130,050,562
28	(332) Reservoirs, Dams, and Waterways	195,625,955	15,693,790	16,157,945	—	—	195,161,800


29	(333) Water Wheels, Turbines, and Generators	176,785,446	13,493,970	713,244	—	—	189,566,172
30	(334) Accessory Electric Equipment	94,377,564	490,305	—	—	—	94,867,869
31	(335) Misc. Power Plant Equipment	20,725,764	42,624	—	—	—	20,768,388
32	(336) Roads, Railroads, and Bridges	2,947,096	122,188	—	—	—	3,069,284
33	TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)	623,091,466	33,264,452	16,913,427	—	—	639,442,491
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	102,231,898	20,405,413	32,076,255	—	—	90,561,056
39	(344) Generators	55,657,436	—	—	—	—	55,657,436
40	(345) Accessory Electric Equipment	19,164,004	—	—	—	—	19,164,004
41	(346) Misc. Power Plant Equipment	29,091,023	—	—	—	—	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)	294,330,077	20,405,413	32,076,255	—	—	282,659,235
44	TOTAL Production Plant (Enter Total of lines 15, 23, 32, and 41)	1,058,622,595	55,278,441	53,099,903	—	—	1,060,801,133
45	3. TRANSMISSION PLANT
46	(350) Land and Land Rights	40,120,055	2,847,269	—	—	—	42,967,324
47	(352) Structures and Improvements	48,939,329	10,826,091	423,877	—	4,266,936	63,608,479
48	(353) Station Equipment	338,651,187	37,736,625	7,438,059	—	(3,948,155)	365,001,598
49	(354) Towers and Fixtures	30,385,864	254,278	—	—	—	30,640,142
50	(355) Poles and Fixtures	457,923,471	38,429,145	1,965,010	—	(76,600)	494,311,006
51	(356) Overhead Conductors and Devices	179,733,447	6,037,165	418,809	—	7,211	185,359,014
52	(357) Underground Conduit	137,878	—	—	—	—	137,878
53	(358) Underground Conductors and Devices	1,935,349	—	—	—	26,615	1,961,964
54	(359) Roads and Trails	4,043,372	—	—	—	—	4,043,372
55	TOTAL Transmission Plant (Enter Total of lines 44 thru 52)	1,101,869,952	96,130,573	10,245,755	—	276,007	1,188,030,777
56	4. DISTRIBUTION PLANT
57	(360) Land and Land Rights	14,731,957	51,702	4,106	—	—	14,779,553
58	(361) Structures and Improvements	38,491,604	3,430,707	368,182	—	2,626,241	44,180,370
59	(362) Station Equipment	246,414,841	24,147,880	5,036,114	—	(3,003,060)	262,523,547
60	(363) Storage Battery Equipment	—	—	—	—	—	—


61	(364) Poles, Towers, and Fixtures	372,403,164	18,680,311	1,082,768	—	90,886	390,091,593
62	(365) Overhead Conductors and Devices	150,470,917	5,604,519	74,577	—	—	156,000,859
63	(366) Underground Conduit	168,176,646	14,172,551	62,731	—	—	182,286,466
64	(367) Underground Conductors and Devices	265,189,715	17,160,624	289,869	—	—	282,060,470
65	(368) Line Transformers	258,401,661	21,210,620	2,216,133	—	—	277,396,148
66	(369) Services	173,892,685	12,772,457	129,116	—	—	186,536,026
67	(370) Meters	76,988,468	16,932,118	6,930,787	—	—	86,989,799
68	(371) Installations on Customer Premises	—	—	—	—	—	—
69	(372) Leased Property on Customer Premises	—	—	—	—	—	—
70	(373&388) Street Lighting and Signal Systems	81,731,152	1,771,644	404,703	—	—	83,098,093
71	(374) Asset Retirement Costs for Distribution Plant	—	—	—	—	—	—
72	TOTAL Distribution Plant (Enter Total of lines 55 thru 68)	1,846,892,810	135,935,133	16,599,086	—	(285,933)	1,965,942,924
73	5. GENERAL PLANT
74	(389) Land and Land Rights	689,633	—	—	—	—	689,633
75	(390) Structures and Improvements	10,698,488	—	73,400	—	—	10,625,088
76	(391) Office Furniture and Equipment	1,209,368	1,662,490	405,191	—	—	2,466,667
77	(392) Transportation Equipment	65,753,018	4,564,891	2,491,507	—	—	67,826,402
78	(393) Stores Equipment	1,143,158	11,950	—	—	—	1,155,108
79	(394) Tools, Shop and Garage Equipment	10,567,559	684,982	156,699	—	—	11,095,842
80	(395) Laboratory Equipment	1,033,178	—	—	—	—	1,033,178
81	(396) Power Operated Equipment	6,542,837	565,924	67,546	—	—	7,041,215
82	(397) Communication Equipment	49,700,312	8,843,727	310,886	—	16,539	58,249,692
83	(398) Miscellaneous Equipment	2,122,710	—	—	—	—	2,122,710
84	SUBTOTAL (Enter Total of lines 71 thru 80)	149,460,261	16,333,964	3,505,229	—	16,539	162,305,535
85	(399) Other Tangible Property	—	—	—	—	—	—
86	TOTAL General Plant (Enter Total of lines 81 and 82)	149,460,261	16,333,964	3,505,229	—	16,539	162,305,535
87	TOTAL (Accounts 101 and 106)	4,189,356,628	308,569,012	83,449,973	—	712,131	4,415,187,798
88	(102) Electric Plant Purchased (See Instr. 8)	—	—				—
89	(Less) (102) Electric Plant Sold (See Instr. 8)	—	—				—
90	(103) Experimental Plant Unclassified	4,244,173	554,577	—	—	—	4,798,750
91	TOTAL Electric Plant in Service(Enter Total of lines 84 thru 87)	4,193,600,801	309,123,589	83,449,973	—	712,131	4,419,986,548

(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		—	—	1,957,036	1,965,340	(303)
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and4)	8,304		—	—	1,957,036	1,965,340
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	27,272,343	484,210	14,748	—	—	27,741,805	(311)
10	(312) Boiler Plant Equipment	199,905,175	1,587,327	214,839	—	—	201,277,663	(312)
11	(313) Engines and Engine-Driven Generators	—	—	—	—	—	—	(313)
12	(314) Turbogenerator Units	26,611,947	1,094,959	64,407	—	—	27,642,499	(314)
13	(315) Accessory Electric Equipment	13,138,219	13,547	7,038	—	—	13,144,728	(315)
14	(316) Misc. Power Plant Equipment	3,100,373	219,867	35,756	—	—	3,284,484	(316)
15	(317) Asset Retirement Costs for Steam	2,663,711	(639,809)	—	—	—	2,023,902
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)	273,058,279	2,760,101	336,788	—	—	275,481,592
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	178,696	—	—	—	261,179	(340)
36	(341) Structures and Improvements	26,801,168	305	617,605	—	—	26,183,868	(341)
37	(342) Fuel Holders, Products, and Accessories	5,304,333	—	20,580	—	—	5,283,753	(342)
38	(343) Prime Movers	128,619,079	597,894	1,734,595	—	—	127,482,378	(343)
39	(344) Generators	87,862,628	—	—	—	—	87,862,628	(344)
40	(345) Accessory Electric Equipment	7,916,002	—	55,169	—	—	7,860,833	(345)
41	(346) Misc. Power Plant Equipment	22,703,885	41,710	130,597	—	—	22,614,998	(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)	280,641,119	818,605	2,558,546	—	—	278,901,178
44	TOTAL Production Plant (Enter Total of lines 15, 23, 32, and 41)	553,699,398	3,578,706	2,895,334	—	—	554,382,770
45	3. TRANSMISSION PLANT
46	(350) Land and Land Rights	1,734,599	138,781	—	—	—	1,873,380	(350)
47	(352) Structures and Improvements	12,393,490	1,146,199	—	—	—	13,539,689	(352)
48	(353) Station Equipment	101,755,312	8,314,824	303,301	—	(119,151)	109,647,684	(353)
49	(354) Towers and Fixtures	—	—	—	—	—	—	(354)
50	(355) Poles and Fixtures	61,186,936	2,513,991	131,497	—	—	63,569,430	(355)
51	(356) Overhead Conductors and Devices	33,204,076	384,533	14,470	—	—	33,574,139	(356)
52	(357) Underground Conduit	640,802	—	—	—	—	640,802	(357)
53	(358) Underground Conductors and Devices	4,705,625	1,384	—	—	—	4,707,009	(358)
54	(359) Roads and Trails	—	—	—	—		—	(359)
55	TOTAL Transmission Plant (Enter Total of lines 44 thru 52)	215,620,840	12,499,712	449,268	—	(119,151)	227,552,133
56	4. DISTRIBUTION PLANT
57	(360) Land and Land Rights	639,546	—	—	—	—	639,546	(360)
58	(361) Structures and Improvements	1,484,027	48,748	—	—	—	1,532,775	(361)
59	(362) Station Equipment	47,142,419	2,030,271	278,894	—	119,151	49,012,947	(362)
60	(363) Storage Battery Equipment	—	—	—	—	—	—	(363)


61	(364) Poles, Towers, and Fixtures	58,931,418	2,997,143	404,150	—	—	61,524,411	(364)
62	(365) Overhead Conductors and Devices	21,791,407	2,091,490	254,182	—	—	23,628,715	(365)
63	(366) Underground Conduit	11,060,486	691,674	—	—	—	11,752,160	(366)
64	(367) Underground Conductors and Devices	63,436,947	3,056,797	541,870	—	—	65,951,874	(367)
65	(368) Line Transformers	43,311,582	2,815,751	—	—	—	46,127,333	(368)
66	(369) Services	22,418,454	1,222,548	149,925	—	—	23,491,077	(369)
67	(370) Meters	14,004,928	792,655	64,848	—	—	14,732,735	(370)
68	(371) Installations on Customer Premises	746,086	10,915	21,640	—	—	735,361	(371)
69	(372) Leased Property on Customer Premises	—	—	—	—	—	—	(372)
70	(373&388) Street Lighting and Signal Systems	9,461,084	3,169,496	1,720,267	—	—	10,910,313	(373)
71	(374) Asset Retirement Costs for Distribution Plant	—	—	—	—	—	—	(374)
72	TOTAL Distribution Plant (Enter Total of lines 55 thru 68)	294,428,384	18,927,488	3,435,776	—	119,151	310,039,247
73	5. GENERAL PLANT
74	(389) Land and Land Rights	106,828	—	1,320	—	—	105,508	(389)
75	(390) Structures and Improvements	1,843,955	35,793	44,699	—	—	1,835,049	(390)
76	(391) Office Furniture and Equipment	7,070	80,585	2,566	—	—	85,089	(391)
77	(392) Transportation Equipment	17,066,995	752,627	536,102	—	—	17,283,520	(392)
78	(393) Stores Equipment	—	36,060	—	—	—	36,060	(393)
79	(394) Tools, Shop and Garage Equipment	2,016,056	156,785	81,741	—	—	2,091,100	(394)
80	(395) Laboratory Equipment	—	—	—	—	—	—	(395)
81	(396) Power Operated Equipment	849,036	89,951	—	—	—	938,987	(396)
82	(397) Communication Equipment	3,104,934	277,311	702,632	—	—	2,679,613	(397)
83	(398) Miscellaneous Equipment	—	—	—	—	—	—	(398)
84	SUBTOTAL (Enter Total of lines 71 thru 80)	24,994,874	1,429,112	1,369,060	—	—	25,054,926
85	(399) Other Tangible Property	—	—	—	—	—	—	(399)
86	TOTAL General Plant (Enter Total of lines 81 and 82)	24,994,874	1,429,112	1,369,060	—	—	25,054,926
87	TOTAL (Accounts 101 and 106)	1,088,751,800	36,435,018	8,149,438	—	1,957,036	1,118,994,416
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)	1,088,751,800	36,435,018	8,149,438	—	1,957,036	1,118,994,416

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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)			1,125,733
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			4,110,361

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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	Yellowstone Gen Station	226,280,753
3	Cochrane U2 Turbine Upgrade	7,292,149
4	Bozeman Division Electric-Cap Blnkt Growth	5,455,498
5	Miller Crk Rebuild	5,013,778
6	Cochrane U2 Gen Restack & Rewind	4,041,523
7	AMI Metering & Infrastructure	3,432,438
8	MT RRR INITIATIVE	2,496,572
9	Ochrane Radial Gate Hoist Upgrad	2,488,629
10	Great Falls 230Kv - EASTSIDE	1,768,366
11	Johnson Lane Bank 1	1,715,623
12	Hauser U1 Turb-Gen Upgrade	1,693,925
13	ADMS Training Development	1,645,439
14	Holter U2 Generator Rewind	1,524,860
15	Ashgrove Transformer Upgrade	1,388,285
16	Bradley Creek 161Kv PCB	1,303,854
17	CROOKED FALLS-GREAT FALLS ES	1,149,101
18	Bozeman Three Rivers Bnk 1	1,135,523
19	Holter U2 Turbine Upgrade	1,129,066
20	Darby Bank 2 Replace	1,109,496
21	Billings Division Electric-Cap Blnkt Growth	1,051,440
22	Madison Spill Gates Screw Jacks	1,003,739
23	Minor Projects (Less than $1,000,000 - 285 items)	29,693,427
24	SOUTH DAKOTA
25	Hurton GT Bank 1	1,602,329
26	Minor Projects (Less than $1,000,000 - 183 items)	9,368,834
43	Total	314,784,647

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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) 1,950,712,066	1,950,712,066
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	143,537,392	143,537,392
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)	143,537,392	143,537,392
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	91,599,411	91,599,411
13	CostOfRemovalOfPlant Cost of Removal	14,338,154	14,338,154
14	SalvageValueOfRetiredPlant Salvage (Credit)	1,725,809	1,725,809
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	104,211,756	104,211,756
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	17,772	17,772
17.2	Transfers	960	960
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)	1,990,020,890	1,990,020,890
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	151,989,438	151,989,438
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	139,268,540	139,268,540
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	140,096,686	140,096,686
25	AccumulatedDepreciationTransmission Transmission	504,039,369	504,039,369
26	AccumulatedDepreciationDistribution Distribution	946,719,166	946,719,166
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	107,907,691	107,907,691
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	1,990,020,890	1,990,020,890

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	1,589,818,437	1,589,818,437
2	Depreciation Provisions for Year, Charged to
3	(403) Depreciation Expense	111,425,479	111,425,479
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)	111,425,479	111,425,479
11	Net Charges for Plant Retired:
12	Book Cost of Plant Retired	83,449,972	83,449,972
13	Cost of Removal	12,843,020	12,843,020
14	Salvage (Credit)	1,507,966	1,507,966
15	TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	94,785,026	94,785,026
16	Other Debit or Cr. Items (Describe, details in footnote):	(17,773)	(17,773)
17	Transfers	959	959
18	Book Cost or Asset Retirement Costs Retired
19	Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	1,606,442,076	1,606,442,076
Section B. Balances at End of Year According to Functional Classification
20	Steam Production	30,892,927	30,892,927
21	Nuclear Production	—	—
22	Hydraulic Production-Conventional	139,268,540	139,268,539
23	Hydraulic Production-Pumped Storage	—	—
24	Other Production	78,783,912	78,783,911
25	Transmission	418,967,210	418,967,210
26	Distribution	841,220,309	841,220,309
27	General	97,309,180	97,309,180
28	TOTAL (Enter Total of lines 20 thru 27)	1,606,442,078	1,606,442,076

South Dakota Operations


Section A. Balances and Changes During Year 2023 SOUTH DAKOTA DATA ONLY
Line No.	Item	Total (c+d+e)	Electric Plant in Service
	(a)	(b)	(c)
1	Balance Beginning of Year	360,893,629	360,893,629
2	Depreciation Provisions for Year, Charged to
3	(403) Depreciation Expense	32,111,914	32,111,914
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)	32,111,914	32,111,914
11	Net Charges for Plant Retired:
12	Book Cost of Plant Retired	8,149,439	8,149,439
13	Cost of Removal	1,495,135	1,495,135
14	Salvage (Credit)	217,843	217,843
15	TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	9,426,731	9,426,731
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)	383,578,812	383,578,812
Section B. Balances at End of Year According to Functional Classification
20	Steam Production	121,096,511	121,096,511
21	Nuclear Production	—	—
22	Hydraulic Production-Conventional	—	—
23	Hydraulic Production-Pumped Storage	—	—
24	Other Production	61,312,774	61,312,774
25	Transmission	85,072,160	85,072,160
26	Distribution	105,498,857	105,498,857
27	General	10,598,510	10,598,510
28	TOTAL (Enter Total of lines 20 thru 27)	383,578,812	383,578,812


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)	360,893,629	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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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			287,451	44,536		331,987
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			388,710	34,124		422,834
8	Canadian Montana Pipeline Corporation	02/15/2002
9	Canadian Montana Pipeline Corporation - Translation Adjustment			1,683,932			1,686,317
10	Canadian Montana Pipeline Corporation - Paid in Capital			1,388,429			1,388,429
11	Canadian Montana Pipeline Corporation - Equity in Undistributed Earnings			1,911,475	195,539		2,107,015
12	Havre Pipeline Company	12/01/2013
13	Havre Pipeline Company - Paid in Capital			13,376,259			16,626,690
14	Havre Pipeline Company - Equity in Undistributed Earnings			1,976,866	1,487,304		3,464,170
15	NorthWestern Energy Solutions	06/01/2018
16	NorthWestern Energy Solutions - Capital Stock			5,793,954			11,852,827
17	NorthWestern Energy Solutions - Equity in Undistributed Earnings			55,682			55,682
18	NorthWestern Public Service - Capital Stock	09/29/2023					1
42	Total Cost of Account 123.1 $		Total	25,343,937	1,281,354		33,374,273

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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)	7,724,941	9,710,818	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)	67,595,939	80,236,296	Electric, Gas, & Common
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	733,334	804,673	Electric & Gas
8	Transmission Plant (Estimated)	767,707	1,269,432	Electric, Gas, & Common
9	Distribution Plant (Estimated)	2,057,268	2,944,092	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)	71,154,248	85,254,493
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	78,879,189	(a)(b) 94,965,311

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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)	856,272	—	1,298,938	2,155,210
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)	8,913,864	13,409,315	39,311,033	61,634,212
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	1,607	—	524,803	526,410
8	Transmission Plant (Estimated)	177,908	906,136	—	1,084,044
9	Distribution Plant (Estimated)	422,841	—	2,131,646	2,554,487
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other
12	TOTAL Account 154 (Enter Total of lines 5 thru 10)	9,516,220	14,315,451	41,967,482	65,799,153
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)	10,372,492	14,315,451	43,266,420	67,954,363

(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)	2,283,502	2,155,210		2,155,210	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)	—	—	61,634,212	61,634,212	Electric, Gas, & Common
6	Assigned to - Operatons and Maintenance	—
7	Production Plant (Estimated)	7,399,061	8,316,399	(7,789,989)	526,410	Electric & Gas
8	Transmission Plant (Estimated)	11,304,264	17,126,102	(16,042,058)	1,084,044	Electric, Gas, & Common
9	Distribution Plant (Estimated)	34,590,716	40,356,652	(37,802,165)	2,554,487	Electric, Gas, & Common
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other	—	—		—
12	TOTAL Account 154 (Enter Total of lines 5 thru 10)	53,294,041	65,799,153	—	65,799,153
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)	55,577,543	67,954,363	—	67,954,363

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)	5,441,439	7,555,608		7,555,608	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)	—	—	18,602,085	18,602,085	Electric & Gas
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	6,008,636	6,344,762	(6,066,499)	278,263	Electric & Gas
8	Transmission Plant (Estimated)	3,979,312	4,227,087	(4,041,698)	185,389	Electric & Gas
9	Distribution Plant (Estimated)	7,872,259	8,883,491	(8,493,888)	389,603	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)	17,860,207	19,455,340	—	19,455,340
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)	23,301,646	27,010,948	—	27,010,948

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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		42,992		59,416
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		39,763		56,187
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:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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	90,602	253	129,019	253
3	SIS Studies	230,479	253	299,617	253
4	Line Interconnection Studies	150,454	253	591,513	253
20	Total	471,535		1,020,149
21	Generation Studies
22	FAC Studies	519,052	253	2,243,519	253
23	SIS Studies	257,737	253	1,070,034	253
24	FEA Studies	271,179	253	558,654	253
25	Optional Studies	41,647	253	120,322	253
39	Total	1,089,615		3,992,529
40	Grand Total	1,561,150		5,012,678

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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)	444,386,121	39,563,304	Various		483,949,425
2	Excess Deferred Income Taxes (Montana)	47,448,837		410.1	2,792,249	(a) 44,656,588
3	Basin Creek Capital Lease (Montana)	4,859,963		243	1,087,070	3,772,893
4	BPA Residential Exchange Program (Montana) - Docket 2018.8.49 Order 7630; Annual Amortization	1,193,372	4,658,761	254	4,681,087	1,171,046
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	11,432,710	24,349,283	(2)407	35,781,993
6	FAS 106 (Montana) - Docket 93.6.24 and Docket 2009.9.129	10,658,733	257,460	(2)926	4,061,074	6,855,119
7	FAS 112 (Montana) - Docket 93.6.24 and Docket 2009.9.129	5,879,275		(2)926	2,192,241	3,687,034
8	Compensated Absences (Montana) - Docket 97.11.219	11,382,102	831,875	242	830,287	11,383,690
9	Pension Plan (Montana)	80,885,087	1,085,861		8,147,332	73,823,616
10	Montana Consumer Counsel Tax (Montana) - Docket 2018.10.67 - Order 7637	639,407	21,066	Various	660,473
11	Montana Public Service Commission (Montana) - Docket 2017.9.78 - Order 7568	3,570,894	4,327,713		5,165,802	2,732,805
12	Natural Gas Transmission Verification Program (Montana) - Docket D2016.11.88	584,247		(2)407	584,247
13	Montana Wildfire Mitigation		1,623,113			1,623,113
14	Asset Retirement Obligation (Montana)	15,421,503	2,385,569			17,807,072
15	Flow-through Income Taxes (South Dakota)	64,652,202	4,849,953			69,502,155
16	Excess Deferred Income Taxes (South Dakota)	6,915,405			167,880	6,747,525
17	Pension Plan (South Dakota)	7,079,702			1,265,007	(b) 5,814,695
18	Manufactured Gas Plants (South Dakota) - Docket NG 11-003	10,962,729	430,042		262,217	11,130,554
19	Field Inventory (South Dakota) - Docket EL 14-106	262,191			89,916	172,275
20	Asset Retirement Obligation (South Dakota)	869,896	135,429			1,005,325
21	Rate Case Costs (South Dakota) Docket EL 23-016		190,623			190,623
44	TOTAL	729,084,376	84,710,052		67,768,875	746,025,553

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssets


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

	MONTANA:
		12/31/2022
		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		3,671	3,671
3	Unbilled Revenue		412,339	412,339
4	Compensation Accruals		450,831	450,831
5	Reserves & Accruals		107,964	107,964
6	Intangible amortization		—	—
7	Pension / Postretirement Benefits		2,956,642	2,956,642
8	Environmental Liability		158,682	158,682
9	Interest Rate Hedge		—	—
10	Customer Advances		1,397,935	1,397,935
11	Excess Tax Depreciation / Other Property			—
12	Net Operating Loss	26,018,461	—	26,018,461
13	Total Electric	26,018,461	5,488,064	31,506,525
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	(3,384,786)	—	(3,384,786)
26	Total Gas	(3,384,786)	6,513,384	3,128,598
27	Other (Specify)	—	319,251	319,251
28	Subtotal	22,633,675	12,320,699	34,954,374
29	Gross-up	8,090,423	4,404,043	12,494,466
30	Total	30,724,098	16,724,742	47,448,840
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	—	319,251	319,251
39	Total	—	319,251	319,251
40
41
42		12/31/2023
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		15,684	15,684
48	Unbilled Revenue		137,446	137,446
49	Compensation Accruals		150,277	150,277
50	Reserves & Accruals		35,988	35,988
51	Intangible amortization		—	—
52	Pension / Postretirement Benefits		985,547	985,547
53	Environmental Liability		52,894	52,894
54	Interest Rate Hedge		—	—
55	Customer Advances		465,978	465,978
56	Excess Tax Depreciation / Other Property			—
57	Net Operating Loss	25,096,836	—	25,096,836
58	Total Electric	25,096,836	1,843,814	26,940,650
59	Gas:
60	Regulatory Assets / Liabilities		(23,077)	(23,077)
61	Unbilled Revenue		481,062	481,062
62	Compensation Accruals		525,970	525,970
63	Reserves & Accruals		104,575	104,575
64	Intangible amortization		—	—
65	Pension / Postretirement Benefits		3,450,731	3,450,731
66	Environmental Liability		185,129	185,129
67	Interest Rate Hedge		—	—
68	Customer Advances		1,137,656	1,137,656
69	Excess Tax Depreciation / Other Property			—
70	Net Operating Loss	—	—	—
71	Total Gas	—	5,862,046	5,862,046
72	Other (Specify)	—	94,696	94,696
73	Subtotal	25,096,836	7,800,556	32,897,392
74	Gross-up	8,970,882	2,788,315	11,759,197
75	Total	34,067,718	10,588,871	44,656,589
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	—	94,696	94,696
84	Total	—	94,696	94,696
85
86
87	SOUTH DAKOTA:
88		12/31/2022
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	3,863,687	—	3,863,687
104	Total Electric	3,863,687	—	3,863,687
105	Gas:
106	Regulatory Assets / Liabilities		—	—
107	Unbilled Revenue		237,268	237,268
108	Compensation Accruals		895,742	895,742
109	Reserves & Accruals		66,861	66,861
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	(154,239)	—	(154,239)
117	Total Gas	(154,239)	1,623,791	1,469,552
118	Other (Specify)	—	129,930	129,930
119	Subtotal	3,709,448	1,753,722	5,463,169
120	Gross-up	986,056	466,179	1,452,235
121	Total	4,695,504	2,219,901	6,915,404
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		12/31/2023
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	3,725,548	—	3,725,548
149	Total Electric	3,725,548	—	3,725,548
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	(148,724)	—	(148,724)
162	Total Gas	(148,724)	1,623,791	1,475,067
163	Other (Specify)	—	129,930	129,930
164	Subtotal	3,576,824	1,753,721	5,330,545
165	Gross-up	950,801	466,179	1,416,980
166	Total	4,527,625	2,219,900	6,747,525
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:

12/31/2023

Year/Period of Report

End of:

2023

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)	2,955	17,013	555	19,968
3	500 kV Operations - Partner's Share (Montana)	149,231		131		149,231
4	PPLM Share of WET Tax (Montana)	2,056	34,977	131	33,999	3,034
5	Unamortized Debt Expense (Monatana)		1,540,495	930.2	65,167	1,475,328
6	Transmission Line Rights (Montana)	136,373		116	90,909	45,464
7	South Dakota Operations:
8	Deferred Fuel for Electric Generation (South Dakota)	866,470	7,446,345	547	8,050,190	262,625
9	Unamortized Debt Expense (South Dakota)	1,489,697	567,457	930.2	1,684,842	372,312
10	Pension Requirement (South Dakota)	7,194,837	3,310,840	253	1,430,564	9,075,113
47	Miscellaneous Work in Progress
48	Deferred Regulatory Comm. Expenses (See pages 350 - 351)
49	TOTAL	9,543,157				11,084,645

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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) 344,029	513,901
3	Unbilled Revenue	6,487,879	7,196,441
4	Compensation Accruals	6,721,853	7,832,297
5	Reserves and Accruals	4,211,397	3,114,841
6	Pension/Postretirement Benefits	13,991,466	11,049,340
7	Other	(b) 26,910,196	105,938,033
8	TOTAL Electric (Enter Total of lines 2 thru 7)	58,666,820	135,644,853
9	Gas
10	Regulatory Asset/Liability	243,159	227,902
11	Unbilled Revenue	2,951,879	3,407,247
12	Compensation Accruals	3,584,320	2,884,161
13	Reserves and Accruals	550,599	421,788
14	Pension/Postretirement Benefits	5,299,035	4,082,073
15	Other	(c) 7,591,054	42,014,497
16	TOTAL Gas (Enter Total of lines 10 thru 15)	20,220,046	53,037,668
17.1	Other (Specify)	(d) 85,056,758	101,200,493
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	163,943,624	289,883,014

Notes

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	344,029	513,901	—	—
2	Unbilled Revenue	5,028,140	5,200,338	1,459,739	1,996,104
3	Compensation Accruals	3,527,251	5,989,387	3,194,602	814,287
4	Reserves & Accruals	3,765,150	2,726,983	446,247	387,858
5	Pension / Postretirement Benefits	14,498,131	11,773,163	(506,665)	(723,823)
6	Environmental Liability	1,678,401	1,598,768	2,168,426	2,087,963
7	Interest Rate Hedge	3,528,578	3,366,964	(90,541)	(50,170)
8	Customer Advances	19,625,332	22,253,438		—
9	NOL Carryforward	—	56,571,417	—	20,109,652
10	Total Electric	51,995,012	109,994,359	6,671,808	24,621,871
11	Gas:
12	Regulatory Liabilities	118,933	199,629	124,226	28,272
13	Unbilled Revenue	1,954,876	2,021,842	997,003	1,385,405
14	Compensation Accruals	1,371,709	2,329,206	2,212,611	554,955
15	Reserves & Accruals	238,732	152,202	311,867	269,586
16	Pension / Postretirement Benefits	5,638,832	4,579,123	(339,797)	(497,050)
17	Environmental Liability	654,227	623,259	1,508,307	1,450,041
18	Interest Rate Hedge	—	—	(65,564)	(36,330)
19	Customer Advances	5,494,084	6,046,233	—	—
20	NOL Carryforward	—	25,726,954	—	8,204,341
21	Total Gas	15,471,393	41,678,448	4,748,653	11,359,220
22	Other (Specify)	34,231,600	38,406,930	53,332,859	62,515,525
23	Total (Acct 190) (Total of lines 10, 20, and 21)	101,698,005	190,079,737	64,753,320	98,496,616

	Account 190 Other (Specify)
	QF Obligations	—	—	—	—
	NOL Carryforward	—	52,584	—	—
	Production Tax Credit	28,869,105	33,278,885	51,227,891	61,004,195
	Other, net	5,362,495	5,075,461	2,104,968	1,511,330
	Total	34,231,600	38,406,930	53,332,859	62,515,525

(b) Concept: AccumulatedDeferredIncomeTaxes


Electric Other:	Balance at Beg of Year	Balance at End of Year
(a)	(b)	(c)
Environmental Liability	3,846,827	3,686,732
Interest Rate Hedge	3,438,037	3,316,794
Customer Advances	19,625,332	22,253,438
NOL Carryforward	—	76,681,069
	26,910,196	105,938,033


Gas Other:	Balance at Beg of Year	Balance at End of Year
(a)	(b)	(c)
Environmental Liability	2,162,534	2,073,301
Interest Rate Hedge	(65,564)	(36,330)
Customer Advances	5,494,084	6,046,232
NOL Carryforward	—	33,931,294
	7,591,054	42,014,497

(d) Concept: AccumulatedDeferredIncomeTaxes


Description and Location	Balance at Beg of Year	Balance at End of Year
Line 17 Detail
NOL Carryforward	—	2,698,126
Production Tax Credit	80,096,996	94,283,080
Other, net	4,959,762	4,219,287
Total	85,056,758	101,200,493

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	200,000,000	0.01		(a) 100	1	0
8	Total	200,000,000			100	1
9	Preferred Stock (Account 204)
10	Preferred Stock - None issued	50,000,000	0.01
13	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:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: CommonStockSharesOutstanding

See Note 1 - Nature of Operations and Basis of Consolidation for further information regarding the holding company reorganization that affected this activity during the twelve months ended December 31, 2023.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2023-12-31

Year/Period of Report

End of:

2023

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	1,999,375,991
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital	79,221,239
15.2	IncreasesDecreasesDueToMiscellaneousPaidInCapital Holding company reorganization	(a) 97,474,439
16	MiscellaneousPaidInCapital Ending Balance Amount	1,981,122,791
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	1,981,122,791

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2023-12-31

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: IncreasesDecreasesDueToMiscellaneousPaidInCapital

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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	First Mortgage Bonds 5.57% (Montana)		239,000,000		1,158,989			03/30/2023	03/30/2033	03/30/2023	03/30/2033	239,000,000	9,744,406
17	Pollution Control Revenue Bonds - 2.00% Series, City of Forsyth (Montana)				1,590,316			08/11/2016	08/01/2023	08/01/2016	08/01/2023		1,109,235
18	Pollution Control Revenue Bonds - 3.88% Series, City of Forsyth (Montana)		144,660,000		1,555,503			06/29/2023	07/01/2028	06/29/2023	07/01/2028	144,660,000	2,802,788
19	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
20	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
21	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
22	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
23	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
24	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
25	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
26	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
27	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
28	First Mortgage Bonds 5.57% (South Dakota)		31,000,000		173,454			03/30/2023	03/30/2033	03/30/2023	03/30/2033	31,000,000	1,295,025
29	First Mortgage Bonds 5.42% (South Dakota)		30,000,000		167,866			05/01/2023	05/01/2023	05/01/2023	05/01/2023	30,000,000	1,084,000
30	Subtotal		2,479,660,000		44,514,192	11,538,984						2,479,660,000	96,559,454
31	Reacquired Bonds (Account 222)
32
33
34
35	Subtotal
36	Advances from Associated Companies (Account 223)
37
38
39
40	Subtotal
41	Other Long Term Debt (Account 224)
42	Senior Unsecured Revolving Line of Credit ($425m)		318,000,000					05/18/2022	05/18/2027	05/18/2022	05/18/2027	318,000,000	14,109,451
43	Senior Unsecured Revolving Line of Credit ($25m)							03/25/2022	03/27/2024	03/27/2022	03/27/2024		3,201
44	Capital Leases (miscellaneous)												1,072
45	Interest Rate Hedge Amortizations												613,744
46	Community Development
47	Subtotal		318,000,000									318,000,000	14,725,324
33	TOTAL		2,797,660,000									2,797,660,000	111,284,778

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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)	194,131,555
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	Equity Earnings of Subsidiaries	1,281,354
9	Deductions Recorded on Books Not Deducted for Return
10	Meals and Entertainment	1,143,806
11	Non-Deductible Dues/Lobbying Expense/Penalties/Professional Fees	94,951
12	Life Insurance/Reserves and Other Misc. Charges	102,064
13	Federal Income Taxes/State Tax Adjustment	4,382,265
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	719,122,756
21	Amortization of Intangibles	215,461
22	Plant Flow Through Items	104,133,074
23	Reserves & Accruals	76,502,299
24	Deferred Book Revenue & Gains	58,869,514
25	Contributions & Advances for Construction	8,804,199
26	Other Miscellaneous	2,113,945
27	Federal Tax Net Income	447,563,577
28	Show Computation of Tax:
29	Federal Tax Net Income	33,103,682
30	Show Computation of Tax:
31	Federal Tax Expense/(Benefit) @ 21%	6,951,773

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	2023	0	0	10,157,918	10,157,918		0		5,386,111			4,771,807
2	FICA and Medicare	Federal Tax	South Dakota	2023	0	0	2,287,535	2,287,535		0		738,753			1,548,782
3	Subtotal Federal Tax				0	0	12,445,453	12,445,453	0	0	0	6,124,864	0	0	6,320,589
4	State Income Tax	State Tax	Montana	2023	2,779,425	0	877,584	8,187	(a) 1,160,572	4,825,768		429,563			1,307,148
5	State Income Tax	State Tax	South Dakota/Nebraska	2023	652,886	0	430,000	0	(b) 895,886	187,000					430,000
6	Subtotal State Tax				3,432,311	0	1,307,584	8,187	264,686	5,012,768	0	429,563	0	0	1,737,148
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	2022	178,250	0		178,250		0
10	Hydro Invasive Species Tax	Other Taxes	Montana	2023	0	0	730,508	547,881		182,627		730,508
11	Heavy Highway Tax	Other Taxes	Montana	2023	0	0	1,890	1,890		0		1,304			586
12	Heavy Highway Tax	Other Taxes	South Dakota	2023	0	0	20	20		0		20			0
13	Personal Property - Auto	Other Taxes	Montana	2023	0	0	5,736	5,736		0		0			5,736
14	WET Tax	Other Taxes	Montana	2022	456,452	0		456,452		0
15	WET Tax	Other Taxes	Montana	2023	0	0	1,755,461	1,302,636		452,825		1,439,774			315,687
16	EELT Tax	Other Taxes	Montana	2022	246,091	0		246,090		1
17	EELT Tax	Other Taxes	Montana	2023	0	0	965,734	721,282		244,452		965,734
18	Consumer Counsel	Other Taxes	Montana	2022	136,071	0		136,071		0
19	Consumer Counsel	Other Taxes	Montana	2023	0	0	589,257	429,194		160,063		457,957			131,300
20	Montana Public Service Commission	Other Taxes	Montana	2022	849,449	0		849,450		1
21	Montana Public Service Commission	Other Taxes	Montana	2023	0	0	3,665,739	2,679,471		986,268		2,042,106			1,623,633
22	Gross Receipts Tax	Other Taxes	South Dakota	2022	393,267	0	0	393,267		0					878
23	Gross Receipts Tax	Other Taxes	South Dakota	2023	0	0	375,390			375,390		267,015			108,375
24	Coal Conversion Tax	Other Taxes	North Dakota	2023	0	0	30,432	30,432		0		30,432
25	Subtotal Other Tax				2,259,580	0	8,120,167	7,978,122	0	2,401,625	0	5,934,850	0	0	2,186,195
26	Property Tax	Property Tax	Montana	2022	88,508,843	0		88,508,843		0
27	Property Tax	Property Tax	Montana	2023	0	0	141,622,152	68,828,092		72,794,060		109,588,956			32,033,196
28	Property Tax - Crow Tribe	Property Tax	Montana	2020	209,784	0		209,784		0
29	Property Tax - Crow Tribe	Property Tax	Montana	2021	209,784	0		209,784		0
30	Property Tax - Crow Tribe	Property Tax	Montana	2022	209,784	0		209,784		0
31	Property Tax - Crow Tribe	Property Tax	Montana	2023	0	0	209,784	209,784		0		84,948			124,836
32	Property Tax - Blackfoot	Property Tax	Montana	2023	0	0	348,409	348,409		0					348,409
33	Property Tax	Property Tax	South Dakota	2022	5,699,807	0	237,874	5,461,933		0		157,115			80,758
34	Property Tax	Property Tax	South Dakota	2023	0	0	5,229,950			5,229,950		4,559,993			669,957
35	Property Tax	Property Tax	Nebraska	2022	754,953	0	22,480	732,473		0					22,480
36	Property Tax	Property Tax	Nebraska	2023	0	0	818,386			818,386					818,386
37	Property Tax	Property Tax	North Dakota	2022	16,413	0	296	16,709		0		296
38	Property Tax	Property Tax	North Dakota	2023	0	0	16,119			16,119		16,119
39	Property Tax	Property Tax	Iowa	2021	71,311	0	1,326	72,637		0		1,326
40	Property Tax	Property Tax	Iowa	2022	110,043	0	0	58,761		51,282		0
41	Property Tax	Property Tax	Iowa	2023	0	0	81,520	0		81,520		81,520
42	Subtotal Property Tax				95,790,722	0	148,067,588	164,866,993	0	78,991,317	0	114,176,043	0	0	33,891,546
43	Subtotal Real Estate Tax				0	0	0	0	0	0	0	0	0	0	0
44	Federal Unemplyment Tax	Unemployment Tax	Montana	2022	2,098	0		2,098		0
45	Federal Unemplyment Tax	Unemployment Tax	Montana	2023	0	0	60,909	59,572		1,337		17,629			43,281
46	Federal Unemplyment Tax	Unemployment Tax	South Dakota	2022	107	0		107		0
47	Federal Unemplyment Tax	Unemployment Tax	South Dakota	2023	0	0	14,619	14,142		477		2,418			12,201
48	State Unemployment Tax	Unemployment Tax	Montana	2022	19,550	0		19,550		0
49	State Unemployment Tax	Unemployment Tax	Montana	2023	0	0	439,376	420,927		18,449		135,992			303,384
50	State Unemployment Tax	Unemployment Tax	South Dakota	2022	330			330		0
51	State Unemployment Tax	Unemployment Tax	South Dakota	2023	0	0	17,631	17,102		529		2,280			15,351
52	Subtotal Unemployment Tax				21,871	0	532,535	533,614	0	20,792	0	158,319	0	0	374,217
53	Use Tax	Sales And Use Tax	Wyoming	2023	856	0	6,946	856		6,946					6,946
54	Use Tax	Sales And Use Tax	South Dakota	2022	102,125	0		102,125		0
55	Use Tax	Sales And Use Tax	South Dakota	2023	0	0	895,087	810,522		84,565					895,086
56	Subtotal Sales And Use Tax				102,981	0	902,033	913,503	0	91,511	0	0	0	0	902,032
57	Federal Income Tax	Income Tax	Montana	2023	10,439,754	0	1,038,315	0	(c) 9,901,439	500,000		2,805,214			3,843,528
58	Federal Income Tax	Income Tax	South Dakota/Nebraska	2023	12,659,824	0	1,206,545	0	(d)(e) 11,453,279	0		1,205,091			1,454
59	Subtotal Income Tax				2,220,070	0	168,230	0	1,551,840	500,000	0	4,010,305	0	0	3,842,074
60	Subtotal Excise Tax				0	0	0	0	0	0	0	0	0	0	0
61	Subtotal Fuel Tax				0	0	0	0	0	0	0	0	0	0	0
62	Subtotal Federal Insurance Tax				0	0	0	0	0	0	0	0	0	0	0
63	Delaware Franchise Tax	Franchise Tax	Montana	2023	0	0	207,888	207,888		0		152,785			55,103
64	Delaware Franchise Tax	Franchise Tax	South Dakota	2023	0	0	42,547	42,547		0		25,028			17,519
65	Subtotal Franchise Tax				0	0	250,435	250,435	0	0	0	177,813	0	0	72,622
66	TOTAL				0	0				0
67	Subtotal Miscellaneous Other Tax				0	0	0	0	0	0	0	0	0	0	0
68	Subtotal Other Federal Tax				0	0	0	0	0	0	0	0	0	0	0
69	Subtotal Other State Tax				0	0	0	0	0	0	0	0	0	0	0
70	Subtotal Other Property Tax				0	0	0	0	0	0	0	0	0	0	0
71	Subtotal Other Use Tax				0	0	0	0	0	0	0	0	0	0	0
72	Subtotal Other Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
73	Subtotal Other License And Fees Tax				0	0	0	0	0	0	0	0	0	0	0
74	Subtotal Payroll Tax				0	0	0	0	0	0	0	0	0	0	0
75	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
76	Subtotal Other Allocated Tax				0	0	0	0	0	0	0	0	0	0	0
77	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
78	Subtotal Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
79	Subtotal Other Taxes And Fees				0	0	0	0	0	0	0	0	0	0	0
40	TOTAL				92,522,773	0	169,178,857	186,996,307	1,287,154	(f) 75,992,477	0	(g)(h) 131,011,757	0	0	38,167,979

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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

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

(e) Concept: TaxAdjustments

Federal Refund of Alternative Minimum Tax credit.

(f) Concept: TaxesAccrued

Montana Operations unfunded reserves for Taxes Accrued (236) are $72,794,059 and $88,508,843 for 2023 and 2022, respectively.

(g) Concept: TaxesAccruedPrepaidAndCharged


Montana Electric - taxes accrued, exclusive of federal and state income taxes			Taxes Charged During the Year 2023
(b)			(c)
Payroll Tax - FICA			4,168,901
Payroll Tax - Medicare			1,217,210
Payroll Tax - FUTA			17,629
Highway Vehicle Use Tax - MT			1,304
Payroll Tax - SUTA - MT			135,992
Real & Personal Property - Transmission			30,360,312
Real & Personal Property - Production			21,693,801
Real & Personal Property - Distribution			57,619,791
City License Tax - MT			—
WET - Montana			1,439,774
EELT - Montana			965,734
Invasive Species Tax - MT			730,508
Cons Council Tax - MT			457,957
MPSC - Montana			2,042,106
Delaware Franchise			152,785
			121,003,804

(h) Concept: TaxesAccruedPrepaidAndCharged


South Dakota Electric - taxes accrued, exclusive of federal and state income taxes	Taxes Charged During the Year 2023
(b)	(c)

Property - South Dakota	$	4,402,877
Property - North Dakota	16,415
Property - Iowa	82,846
Highway Vehicle Use Tax - SD	20
Coal Conversion Facility - N Dakota	30,432
Gross Revenue - South Dakota	267,015
Delaware Franchise	25,028
Vehicle - South Dakota	—
Payroll Tax - FICA	571,802
Payroll Tax - Medicare	166,951
Payroll Tax - FUTA	2,418
Payroll Tax - SUTA - SD	2,279
	$	5,568,083

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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%				411.4
8	TOTAL Electric (Enter Total of lines 2 thru 7)
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
11	Other - 30	388,447			411.4	(a) 129,483		258,964	5 years
12	OTHER TOTAL	388,447				129,483		258,964
13	Account 255 balance	388,447				129,483		258,964
47	OTHER TOTAL
48	GRAND TOTAL	388,447						258,964

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAmount


The other 30% amount disclosed on Page 266 is comprised of the following amounts:
129,483			Amortization
—			New Credits
129,483			Allocation to Current Year's Income

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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)	76,253,877	Various	20,338,840	13,277,368	69,192,405
3	Projects & Studies Prepaid by Customers (Montana)	26,129,053		37,798,143	39,330,668	27,661,578
4	Deferred Compensation (Montana)			2,937,388	15,967,198	13,029,810
5	Permanent Uncertain Tax Positions (Montana)			4,673,175	5,038,620	365,445
6	Other Minor Items (7) - some are amortized over various periods (Montana)	4,682,955		2,612,494	655,514	2,725,975
7	South Dakota Operations:
8	Family Protector Plan Future Payments (South Dakota)	300,332				300,332
9	Projects & Studies Prepaid by Customer (South Dakota)	7,652		16,259	3,405	5,202
10	Deferred Compensation (South Dakota)	20,894,504		23,862,956	2,968,452
11	Permanent Uncertain Tax Positions (South Dakota)			49,476	8,455	41,021
12	Other Minor Items (4) - some are amortized over various periods (South Dakota)	3,645,829		107,040	3,041,694	6,580,483
13	Corporate:
14	Minor Item (Corporate)	2,966,312		2,966,312
15	Permanent Uncertain Tax Positions (Corporate)	23,271,989		7,181,253	11,433,876	27,524,612
47	TOTAL	158,152,503		102,543,336	91,725,250	147,334,417

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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

5.2

Other

TOTAL Electric (Enter Total of lines 3 thru 7)

Gas

Defense Facilities

Pollution Control Facilities

Other

12.1

Other

12.2

Other

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:

12/31/2023

Year/Period of Report

End of:

2023

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) 406,122,015	153,250,212								559,372,227
3	Gas	66,381,034	56,624,971								123,006,005
4	Other (Specify)	17,282,908		1,457,740							18,740,648
5	Total (Total of lines 2 thru 4)	455,220,141	209,875,183	1,457,740							663,637,584
6
7
8
9	TOTAL Account 282 (Total of Lines 5 thru 8)	455,220,141	209,875,183	1,457,740							663,637,584
10	Classification of TOTAL
11	Federal Income Tax	357,641,893	164,746,758	1,084,067			282				521,304,584
12	State Income Tax	97,578,248	45,128,425	373,673					282		142,333,000
13	Local Income Tax

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	341,070,849	127,465,286	—			468,536,135
3	Gas	56,872,851	48,588,512	—			105,461,363
4	Other	(17,282,908)	—	(1,457,740)			(18,740,648)
5	Total	380,660,792	176,053,798	(1,457,740)			555,256,850
6
7
8
9	Total	380,660,792	176,053,798	(1,457,740)			555,256,850
10	Classification Total
11	Federal Income Tax	283,082,544	130,925,373	(1,084,067)	—		412,923,850
12	State Income Tax	97,578,248	45,128,425	(373,673)		—	142,333,000
13	Local Income Tax

SOUTH DAKOTA
1	Account 282
2	Electric	65,051,166	25,784,926	—			90,836,092
3	Gas	9,508,183	8,036,459	—			17,544,642
4	Other	—	—	—			—
5	Total	74,559,349	33,821,385	—			108,380,734
6
7
8
9	Total	74,559,349	33,821,385	—			108,380,734
10	Classification Total
11	Federal Income Tax	74,559,349	33,821,385	—			108,380,734
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:

12/31/2023

Year/Period of Report

End of:

2023

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) 45,019,880		31,500,927							13,518,953
4	Excess Tax Depreciation	85,325,709			8,910,782						94,236,491
9	TOTAL Electric (Total of lines 3 thru 8)	130,345,589		31,500,927	8,910,782						107,755,444
10	Gas
11	Regulatory Assets	16,659,486		8,113,919							8,545,567
12	Excess Tax Depreciation	19,650,048			5,571,721						25,221,769
17	TOTAL Gas (Total of lines 11 thru 16)	36,309,534		8,113,919	5,571,721						33,767,336
18	TOTAL Other	87,743,520			2,626,171	643,803					89,725,888
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	254,398,643		39,614,846	17,108,674	643,803					231,248,668
20	Classification of TOTAL
21	Federal Income Tax	198,730,276		29,712,158	11,157,788	616,092					179,559,814
22	State Income Tax	55,668,367		9,902,688	5,950,886	27,711					51,688,854
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	43,797,018	—	30,556,745	—	—	—	—	13,240,273
10	Excess Tax Depreciation	76,993,952	—	—	8,181,743	—	—	—	85,175,695
14	Total Electric	120,790,970	—	30,556,745	8,181,743	—	—	—	98,415,968

16	Gas:
18	Regulatory Assets	13,332,547	—	8,074,743	—	—	—	—	5,257,804
24	Excess Tax Depreciation	17,516,120	—	—	5,025,141	—	—	—	22,541,261
27	Total Gas	30,848,667	—	8,074,743	5,025,141	—	—	—	27,799,065

29	Other, Net	93,543,598	—	—	56,736	108,107	—	—	93,492,227

31	Total (Acct 283) (Lines 9,17 & 18)	245,183,235	—	38,631,488	13,263,620	108,107	—	—	219,707,260

33	Classification of Total
34	Federal Income Tax	182,333,645	—	28,728,800	9,863,661	80,396	—	—	163,388,110
35	State Income Tax	62,849,590	—	9,902,688	3,399,959	27,711	—	—	56,319,150
36	Local Income Tax
37		245,183,235	—	38,631,488	13,263,620	108,107			219,707,260

SOUTH DAKOTA
1	Account 283
2	Electric:
4	Regulatory Assets	1,222,862	—	944,182	—	—	—	—	278,680
10	Excess Tax Depreciation	8,331,757	—	—	729,039	—	—	—	9,060,796
14	Total Electric	9,554,619	—	944,182	729,039	—	—	—	9,339,476
							—	—
16	Gas:						—	—
18	Regulatory Assets	3,326,939	—	39,176	—	—	—	—	3,287,763
24	Excess Tax Depreciation	2,133,928	—	—	546,580	—	—	—	2,680,508
27	Total Gas	5,460,867	—	39,176	546,580	—	—	—	5,968,271
		—							—
29	Other, Net	(126,913)	—	—	18,508	—	—	—	(108,405)

31	Total (Acct 283) (Lines 9,17 & 18)	14,888,573	—	983,358	1,294,127	—	—	—	15,199,342

33	Classification of Total
34	Federal Income Tax	14,888,573	—	983,358	1,294,127	—	—	—	15,199,342
35	State Income Tax
36	Local Income Tax
37		14,888,573	—	983,358	1,294,127	—			15,199,342

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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)	129,066,336		13,452,166	2,255,938	(a) 117,870,108
2	Deferred Gas Storage Sales (Montana) - Docket D2001.1.1; Amortization 2001 - 2039	7,045,944	(2)407	420,516		6,625,428
3	Montana Public Service Commission Consumer Counsel Taxes (Montana) - Dockets 2017.9.78 and 2018.10.67	1,908,900	Various	3,658,305	1,791,849	42,444
4	CTC QF Over/Under Collections (Montana) - Docket 97.9.90 and Docket 2001.1.15; Annual Amortization	756,325		592,303	740,779	904,801
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	1		616,025	30,073,585	29,457,559
6	Natural Gas Regulatory Deferrals (Montana)	27,556		2,333,885	2,492,345	186,016
7	Excess Deferred Income Taxes (South Dakota)	19,922,861	(2)407	1,411,310		(b) 18,511,551
8	Current Ad Valorem True-Up (South Dakota) - Docket GE98-001	390,314	(2)407	531,815	1,031,332	889,831
9	Aberdeen Manufactured Gas Plant (South Dakota) - Docket NG 11-003	591,549		591,549
10	Tax Cut Jobs Act Deferral (South Dakota) - Docket NG-0095 and GE17-003	155,000		51,667		103,333
11	Unbilled Revenues (South Dakota)	11,536,118		4,819,134	9,287,307	16,004,291
12	SD Gas Rate Refund			1,164,262	1,215,929	51,667
41	TOTAL	171,400,902		29,642,937	48,889,064	190,647,029

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilities


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

	MONTANA:
		12/31/2022
		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		1,080,161	1,080,161	1,083,832	—	1,083,832
3	Unbilled Revenue		—	—	412,339	—	412,339
4	Compensation Accruals		—	—	450,831	—	450,831
5	Reserves & Accruals		—	—	107,964	—	107,964
6	Intangible amortization		(4,772,349)	(4,772,349)	(4,772,349)	—	(4,772,349)
7	Pension / Postretirement Benefits		—	—	2,956,642	—	2,956,642
8	Environmental Liability		—	—	158,682	—	158,682
9	Interest Rate Hedge		—	—	—	—	—
10	Customer Advances		—	—	1,397,935	—	1,397,935
11	Excess tax Depreciation / Other Property	(69,779,321)	—	(69,779,321)	(69,779,321)	(14,736,937)	(84,516,258)
12	Net Operating Loss			—	26,018,461	—	26,018,461
13	Total Electric	(69,779,321)	(3,692,188)	(73,471,509)	(41,964,984)	(14,736,937)	(56,701,921)
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		(3,105,058)	(3,105,058)	(3,105,058)	—	(3,105,058)
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	(16,034,101)	—	(16,034,101)	(16,034,101)	(4,247,115)	(20,281,216)
25	Net Operating Loss			—	(3,384,786)	—	(3,384,786)
26	Total Gas	(16,034,101)	(5,218,040)	(21,252,141)	(18,123,543)	(4,247,115)	(22,370,658)
27	Other (Specify)	(356,293)	—	(356,293)	(37,042)	163,735	126,693
28	Subtotal	(86,169,715)	(8,910,228)	(95,079,943)	(60,125,569)	(18,820,317)	(78,945,886)
29	Gross-up	(30,801,426)	(3,184,967)	(33,986,393)	(21,491,927)	(6,727,336)	(28,219,263)
30	Total	(116,971,141)	(12,095,195)	(129,066,336)	(81,617,496)	(25,547,653)	(107,165,149)
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	(356,293)	—	(356,293)	(37,042)	163,735	126,693
39	Total	(356,293)	—	(356,293)	(37,042)	163,735	126,693
40


41
42		12/31/2023
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		345,592	345,592	361,276	—	361,276
48	Unbilled Revenue		—	—	137,446	—	137,446
49	Compensation Accruals		—	—	150,277	—	150,277
50	Reserves & Accruals		—	—	35,988	—	35,988
51	Intangible amortization		(1,590,783)	(1,590,783)	(1,590,783)	—	(1,590,783)
52	Pension / Postretirement Benefits		—	—	985,547	—	985,547
53	Environmental Liability		—	—	52,894	—	52,894
54	Interest Rate Hedge		—	—	—	—	—
55	Customer Advances		—	—	465,978	—	465,978
56	Excess Tax Depreciation / Other Property	(66,495,795)	—	(66,495,795)	(66,495,795)	(4,912,312)	(71,408,107)
57	Net Operating Loss			—	25,096,836	—	25,096,836
58	Total Electric	(66,495,795)	(1,245,191)	(67,740,986)	(40,800,336)	(4,912,312)	(45,712,648)
59	Gas:
60	Regulatory Assets / Liabilities		(1,901,684)	(1,901,684)	(1,924,761)	—	(1,924,761)
61	Unbilled Revenue		—	—	481,062	—	481,062
62	Compensation Accruals		—	—	525,970	—	525,970
63	Reserves & Accruals		—	—	104,575	—	104,575
64	Intangible amortization		(2,794,553)	(2,794,553)	(2,794,553)	—	(2,794,553)
65	Pension / Postretirement Benefits		—	—	3,450,731	—	3,450,731
66	Environmental Liability		—	—	185,129	—	185,129
67	Interest Rate Hedge		—	—	—	—	—
68	Customer Advances		—	—	1,137,656	—	1,137,656
69	Excess Tax Depreciation / Other Property	(14,061,134)	—	(14,061,134)	(14,061,134)	(1,415,705)	(15,476,839)
70	Net Operating Loss			—	—	—	—
71	Total Gas	(14,061,134)	(4,696,237)	(18,757,371)	(12,895,325)	(1,415,705)	(14,311,030)
72	Other (Specify)	(333,605)	—	(333,605)	(238,909)	106,956	(131,953)
73	Subtotal	(80,890,534)	(5,941,428)	(86,831,962)	(53,934,570)	(6,221,061)	(60,155,631)
74	Gross-up	(28,914,379)	(2,123,767)	(31,038,146)	(19,278,950)	(2,223,723)	(21,502,673)
75	Total	(109,804,913)	(8,065,195)	(117,870,108)	(73,213,520)	(8,444,784)	(81,658,304)
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	(333,605)	—	(333,605)	(238,909)	106,956	(131,953)
84	Total	(333,605)	—	(333,605)	(238,909)	106,956	(131,953)
85
86
87	SOUTH DAKOTA:
88		12/31/2022
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	(14,378,122)	—	(14,378,122)	(14,378,122)	(13,001,493)	(27,379,615)
103	Net Operating Loss			—	3,863,687	—	3,863,687
104	Total Electric	(14,378,122)	—	(14,378,122)	(10,514,435)	(13,001,493)	(23,515,928)
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		—	—	66,861	—	66,861
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	(1,123,706)	—	(1,123,706)	(1,123,706)	(2,099,506)	(3,223,212)
116	Net Operating Loss			—	(154,239)	—	(154,239)
117	Total Gas	(1,123,706)	(238,951)	(1,362,657)	106,895	(2,099,506)	(1,992,611)
118	Other (Specify)	—	1,719	1,719	131,649	—	131,649
119	Subtotal	(15,501,828)	(237,232)	(15,739,060)	(10,275,891)	(15,100,999)	(25,376,890)
120	Gross-up	(4,120,739)	(63,062)	(4,183,801)	(2,731,566)	(4,014,190)	(6,745,756)
121	Total	(19,622,567)	(300,294)	(19,922,861)	(13,007,457)	(19,115,189)	(32,122,646)
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		12/31/2023
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	(13,669,144)	—	(13,669,144)	(13,669,144)	(12,536,650)	(26,205,794)
148	Net Operating Loss			—	3,725,548	—	3,725,548
149	Total Electric	(13,669,144)	—	(13,669,144)	(9,943,596)	(12,536,650)	(22,480,246)
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	(717,749)	—	(717,749)	(717,749)	(2,024,442)	(2,742,191)
161	Net Operating Loss			—	(148,725)	—	(148,725)
162	Total Gas	(717,749)	(238,951)	(956,700)	518,366	(2,024,442)	(1,506,076)
163	Other (Specify)	—	1,719	1,719	131,649	—	131,649
164	Subtotal	(14,386,893)	(237,232)	(14,624,125)	(9,293,581)	(14,561,092)	(23,854,673)
165	Gross-up	(3,824,364)	(63,062)	(3,887,426)	(2,470,445)	(3,870,670)	(6,341,115)
166	Total	(18,211,257)	(300,294)	(18,511,551)	(11,764,026)	(18,431,762)	(30,195,788)
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:

12/31/2023

Year/Period of Report

End of:

2023

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	476,229,860	426,147,770	3,398,191	3,463,605	373,750	368,037
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	514,333,224	454,204,813	3,853,669	3,861,758	89,421	87,947
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	78,074,278	74,495,380	740,374	756,160	139	138
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	18,993,653	16,226,737	36,314	40,667	3,755	3,771
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	831,202	894,925	6,993	7,275	275	274
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales	1,031,286	879,131	7,562	7,442	344	342
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	1,089,493,503	972,848,756	8,043,103	8,136,907	467,684	460,509
11	SalesForResaleAbstract (447) Sales for Resale	86,727,064	51,420,884	1,213,387	1,058,843
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	1,176,220,567	1,024,269,640	9,256,490	9,195,750	467,684	460,509
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	17,488	1,979,898
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	1,176,203,079	1,026,249,538	9,256,490	9,195,750	467,684	460,509
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	409,477	462,318
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	199,581	214,473
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	(a) 4,853,208	4,372,406
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 21,438,190	17,510,620
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	79,001,700	78,400,732
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
26	OtherOperatingRevenues TOTAL Other Operating Revenues	105,902,156	100,960,549
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	(c) 1,282,105,235	1,127,210,087
Line12, column (b) includes $ 58,585,998 of unbilled revenues.
Line12, column (d) includes 439,419 MWH relating to unbilled revenues

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: RentFromElectricProperty

Rent from South Dakota electric property was $324,215 and $223,992 for 2023 and 2022, respectively.

Rent from Montana electric property was $4,528,992 and $4,148,415 for 2023 and 2022, respectively.

(b) Concept: OtherElectricRevenue


	YTD Dec		YTD Dec		Montana Operations
Total Electric Revenue	2023		2022		2023		2022
Rate Revenue	1,089,493,503		972,848,756		915,681,902		792,105,531
Sales for Resale & Coops	86,727,064		51,420,884		86,727,064		51,420,884
Provision for Rate Refund - MPSC	—		—		—		—
Provision for Rate Refund - FERC	(17,487)		1,979,898		(8,110)		1,979,898
Forfeited Discounts	409,477		462,318		—		—
Service Revenue	199,581		214,473		(56)		(2,835)
Rent	4,853,208		4,372,406		4,528,992		4,148,415
Transmission (456.1)	79,001,700		78,011,672		72,267,078		71,875,119
SPP Sch 7-8 Form Rate	—		389,060		—		—
Other	21,438,189		17,510,620		20,910,656		16,568,629
	1,282,105,235		1,127,210,087		1,100,107,526		938,095,641

	YTD Dec		YTD Dec		Montana Operations
Other Electric Revenue (456)	2023		2022		2023		2022
Ancillary Services:
Scheduling, System Control and Dispatch	$	1,721,705	$	1,875,805	$	1,721,705	$	1,875,805
Regulation and Frequency Response	1,220,113		1,131,370		1,220,113		1,131,370
Energy Imbalance	16,530,210		8,972,921		16,530,210		8,972,921
Other Transmission Revenue	(1,582,788)		1,150,552		(1,582,788)		1,150,552
Low Income Housing	2,974,391		2,354,251		2,974,391		2,354,251
Steam Sales	506,006		920,670		—		—
Sale of Materials	28,074		67,902		6,544		46,746
Miscellaneous	40,480		1,037,149		40,480		1,036,984
	$	21,438,191	$	17,510,620	$	20,910,655	$	16,568,629


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	408,341,964	2,795,247	322,489
4	(442) Small Commercial and Industrial	443,255,228	3,186,616	76,508
5	(442) Large Commercial and Industrial	45,958,278	306,226	79
6	(444) Public Street and Highway Lighting	17,095,146	26,245	3,609
9	(448) Interdepartmental Sales	1,031,286	7,562	344
10	TOTAL Sales to Ultimate Consumers	915,681,902	6,321,896	403,029
11	(447) Sales for Resale	86,727,064
12	Total Sales of Electricity	1,002,408,966
13	(449.1) Provision for Transmission Rate Refund	8,110
14	Total Revenues Net of Prov. For Refunds	1,002,400,856
16	(450) Forfeited Discounts
17	(451) Miscellaneous Service Revenue	(56)
19	(454) Rent from Electric Property	4,528,992
21	(456) Other Electric Revenues	20,910,656
22	(456.1) Transmission of Electricity for Others	90,562,183
25	(449.1) Provision for Transmission Rate Refund	—
26	TOTAL Other Operating Revenues	116,001,775
27	TOTAL Electric Operating Revenues	1,118,402,631

	Line 12, column (b) includes $	58,585,998	of unbilled revenues
	Line 12, column (d) includes	439,420	MWH relating to unbilled rev

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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	401,085	48,252,188	39,170	10,240	0.1203
2	SD 11 Resid Space Htg 1 Meter	186,428	18,431,573	11,025	16,910	0.0989
3	SD 14 Resid Space Htg 2 Meters	14,693	952,934	1,027	14,307	0.0649
4	SD 15 Residential Dual-Fuel	78	4,817	7	11,143	0.0618
5	SD 95 Reddy Guard	660	246,384	32	20,625	0.3733
6	MT Residential	2,594,946	379,578,347	322,489	8,047	0.1463
7	MT Unbilled Revenue	200,301	28,763,617
41	TOTAL Billed Residential Sales	3,197,890	447,466,243	373,750	8,556	0.1399
42	TOTAL Unbilled Rev. (See Instr. 6)	200,301	28,763,617
43	TOTAL	3,398,191	476,229,860	373,750	9,092	0.1401

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	2,097	219,989	70	29,957	0.1049
2	SD 17 Irrigation Power	445	58,991	18	24,722	0.1326
3	SD 21 General Service	74,197	11,412,384	8,647	8,581	0.1538
4	SD 23 Comm Water Heat	593	54,118	58	10,224	0.0913
5	SD 24 Comm Space Heat	43,586	2,880,006	590	73,875	0.0661
6	SD 25 Comm Heating	39,823	3,869,723	803	49,593	0.0972
7	SD 33 Industrial Power	159,881	20,962,243	2,098	76,206	0.1311
8	SD 34 Industrial Power	343,268	30,766,281	429	800,159	0.0896
9	SD 70 Controlled Off-Peak	1,261	91,485	4	315,250	0.0725
10	SD 73 Small Qual Facil Rider, 38 P to P		216,836	17		0.0000
11	SD 95 Reddy Guard	1,901	545,940	179	10,620	0.2872
12	MT General Service - 1	2,895,081	405,036,453	74,439	38,892	0.1399
13	MT Irrigation	81,079	11,898,677	2,069	39,188	0.1468
14	MT General Service - 1 Unbilled	210,457	26,320,098
41	TOTAL Billed Small or Commercial	3,643,212	488,013,126	89,421	40,742	0.1340
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	210,457	26,320,098
43	TOTAL Small or Commercial	3,853,669	514,333,224	89,421	43,096	0.1335

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	434,148	32,116,000	60	7,235,800	0.0740
2	MT General Service - 2	277,565	42,455,995	79	3,513,481	0.1530
3	MT General Service - 2 Unbilled	28,661	3,502,283
41	TOTAL Billed Large (or Ind.) Sales	711,713	74,571,995	139	5,120,237	0.1048
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	28,661	3,502,283
43	TOTAL Large (or Ind.)	740,374	78,074,278	139	5,326,432	0.1055

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	10,069	1,898,507	146	68,966	0.1885
2	MT Lighting	26,245	17,095,146	3,609	7,272	0.6514
41	TOTAL Billed Public Street and Highway Lighting	36,314	18,993,653	3,755	9,671	0.5230
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	36,314	18,993,653	3,755	9,671	0.5230

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	6,993	831,202	275	25,429	0.1189
41	TOTAL Billed Other Sales to Public Authorities	6,993	831,202	275	25,429	0.1189
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	6,993	831,202	275	25,429	0.1189

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	7,562	1,031,286	344	21,983	0.1364
41	TOTAL Billed Interdepartmental Sales	7,562	1,031,286	344	21,983	0.1364
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	7,562	1,031,286	344	21,983	0.1364

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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		17,488
41	TOTAL Billed Provision For Rate Refunds		17,488
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL		17,488

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	7,603,684	1,030,907,505	467,684	16,258	0.1356
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	439,419	58,585,998
43	TOTAL - All Accounts	8,043,103	1,089,493,503	467,684	16,258	0.1433

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	18		1,041		1,041
4	BC HYDRO DISTRIBUTION	LF	Reserve Energy	0	0	0	13		953		953
5	BONNEVILLE POWER ADMINISTRATION	LF	Reserve Energy	0	0	0	41		1,832		1,832
6	GRID FORCE ENERGY MANAGEMENT, LLC	LF	Reserve Energy	0	0	0	351		28,518		28,518
7	GRANT COUNTY PUD	LF	Reserve Energy	0	0	0	14		772		772
8	PACIFICORP	LF	Reserve Energy	0	0	0	28		3,612		3,612
9	PORTLAND GENERAL ELECTRIC COMPANY	LF	Reserve Energy	0	0	0	29		1,999		1,999
10	BHE Glacier Wind	LF	Reserve Energy	0	0	0	21		1,303		1,303
11	BHE Wind Watch	LF	Reserve Energy	0	0	0	7		484		484
12	TALEN MONTANA, LLC	LF	Reserve Energy	0	0	0	71		3,846		3,846
13	IDAHO POWER COMPANY	LF	Reserve Energy	0	0	0	35		1,876		1,876
14	PUGET SOUND ENERGY, INC	LF	Reserve Energy				18		1,546		1,546
15	SACRAMENTO MUNICIPAL UTILITY DISTRICT	LF	Reserve Energy				17		1,164		1,164
16	CHELAN COUNTY PUD	LF	Reserve Energy	0	0	0	8		1,016		1,016
17	SEATTLE CITY LIGHT	LF	Reserve Energy	0	0	0	6		387		387
18	AVANGRID	LF	Reserve Energy	0	0	0	14		1,085		1,085
19	TACOMA POWER	LF	Reserve Energy				11		369		369
20	SUPPLY
21	Avangrid Renewables, LLC	SF	Market-Based Rate				41,968		3,152,941		3,152,941
22	Avista Corporation	SF	Market-Based Rate				27,766		1,780,685		1,780,685
23	Basin Electric Power Cooperative	SF	Market-Based Rate				1,742		203,875		203,875
24	Black Hills Power Inc	SF	Market-Based Rate				2,620		75,365		75,365
25	Bonneville Power Administration	SF	Market-Based Rate				129,225		8,959,682		8,959,682
26	Clatskanie Peoples Utility District - Electric	SF	Market-Based Rate				11,352		640,058		640,058
27	Dynasty Power, Inc.	SF	Market-Based Rate				25,840		1,449,019		1,449,019
28	EDF Trading North America, LLC	SF	Market-Based Rate				12,190		468,809		468,809
29	Energy Keepers, Inc.	SF	Market-Based Rate				15,348		1,364,629		1,364,629
30	Eugene Water & Electric Board	SF	Market-Based Rate				28,321		1,878,750		1,878,750
31	Constellation Energy Generation, LLC	SF	Market-Based Rate				192		26,940		26,940
32	Guzman Energy, LLC	SF	Market-Based Rate				8,367		451,569		451,569
33	Heartland Generation LTD	SF	Market-Based Rate				12,240		579,950		579,950
34	Idaho Power Company	SF	Market-Based Rate				775		50,000		50,000
35	Mercuria Energy America, Inc.	SF	Market-Based Rate				1,320		161,476		161,476
36	Macquarie Energy LLC	SF	Market-Based Rate				91,251		4,936,864		4,936,864
37	Morgan Stanley Capital Group, Inc.	SF	Market-Based Rate				211,950		18,787,500		18,787,500
38	Pacificorp	SF	Market-Based Rate				2,975		285,980		285,980
39	ConocoPhillips Company	SF	Market-Based Rate				1,024		98,206		98,206
40	Portland General Electric	SF	Market-Based Rate				43,950		2,922,530		2,922,530
41	Powerex Corporation	SF	Market-Based Rate				139,820		6,891,686		6,891,686
42	Puget Sound Energy	SF	Market-Based Rate				20,202		1,432,125		1,432,125
43	Rainbow Energy Marketing Corporation	SF	Market-Based Rate				17,640		970,422		970,422
44	Seattle City Light	SF	Market-Based Rate				20,936		1,733,619		1,733,619
45	Shell Energy North America (US), L.P.	SF	Market-Based Rate				236,154		19,590,934		19,590,934
46	Tacoma Power	SF	Market-Based Rate				3,887		190,100		190,100
47	Tenaska Power Services	SF	Market-Based Rate				6,111		418,247		418,247
48	The Energy Authority, Inc.	SF	Market-Based Rate				27,191		2,034,780		2,034,780
49	Tiber Montana, LLC	LU	Market-Based Rate				22,755		1,181,488		1,181,488
50	TransAlta Energy Marketing (US) Inc.	SF	Market-Based Rate				46,973		3,912,858		3,912,858
51	Vitol Inc-Electric	SF	Market-Based Rate				265		34,325		34,325
52	Western Area Power Administration	SF	Market-Based Rate				335		9,850		9,850
53	Rounding								1		1
15	Subtotal - RQ
16	Subtotal-Non-RQ						1,213,387		86,727,064		86,727,064
17	Total						1,213,387		86,727,064		86,727,064

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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) 782,804	786,697
5	FuelSteamPowerGeneration (501) Fuel	(b) 54,222,808	54,117,061
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	2,770,956	2,737,648
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	966,678	1,213,454
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	4,187,054	3,581,075
11	RentsSteamPowerGeneration (507) Rents	29,911	29,365
12	Allowances (509) Allowances
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	62,960,211	62,465,300
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	896,280	1,128,801
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	1,062,779	1,068,468
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	7,299,279	6,817,890
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	1,513,816	2,009,348
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	1,035,120	971,371
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	11,807,274	11,995,878
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	74,767,485	74,461,178
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	773,199	678,516
45	WaterForPower (536) Water for Power	1,010,210	949,611
46	HydraulicExpenses (537) Hydraulic Expenses	3,726,277	3,654,685
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	3,430,921	3,662,440
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	3,025,811	2,903,754
49	RentsHydraulicPowerGeneration (540) Rents	824,957	808,040
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	12,791,375	12,657,046
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering	650,985	560,467
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	507,445	715,688
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	151,023	612,490
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	1,036,087	1,228,566
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	211,995	215,886
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	2,557,535	3,333,097
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	15,348,910	15,990,143
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	619,601	722,188
63	Fuel (547) Fuel	25,955,883	33,724,390
64	GenerationExpenses (548) Generation Expenses	8,666,896	8,025,712
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	1,302,761	2,406,135
66	RentsOtherPowerGeneration (550) Rents
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	36,545,141	44,878,425
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering	63,598	50,511
70	MaintenanceOfStructures (552) Maintenance of Structures	105,114	158,104
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	2,545,958	2,441,596
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	147,267	75,545
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	2,861,937	2,725,756
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	39,407,078	47,604,181
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	281,449,711	289,399,612
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	348,013	304,469
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	(c) 67,814,770	39,066,467
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	349,612,494	250,637,614
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	479,135,967	388,693,116
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	3,061,390	2,639,609
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	985,226	936,249
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	878,169	1,029,220
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	1,149,993	1,357,193
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	105,401	94,637
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	2,085,130	1,614,827
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	962,080	1,359,806
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	25,984,743	26,538,502
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	235,553	242,962
98	RentsTransmissionElectricExpense (567) Rents	1,050,206	1,101,354
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	36,497,891	36,914,359
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	571,893	590,613
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	35,350	61,337
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	1,312,307	1,442,191
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	13,110	2,873
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	692,016	747,867
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	3,092,463	3,602,567
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	189	370
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	5,717,328	6,447,818
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	42,215,219	43,362,177
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	388,799	326,294
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation	111,085	93,227
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance	55,543	46,614
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	555,427	466,135
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)	555,427	466,135
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	3,879,920	3,603,183
135	LoadDispatching (581) Load Dispatching
136	StationExpensesDistribution (582) Station Expenses	1,623,216	1,518,190
137	OverheadLineExpenses (583) Overhead Line Expenses	2,265,267	2,133,592
138	UndergroundLineExpenses (584) Underground Line Expenses	2,912,074	2,859,334
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	111,930	163,058
140	MeterExpenses (586) Meter Expenses	2,171,113	2,369,994
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	1,812,434	1,927,758
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	3,462,625	3,145,062
143	RentsDistributionExpense (589) Rents	72,610	81,786
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	18,311,189	17,801,957
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	1,527,311	1,647,819
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	19,450	28,996
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	607,353	652,201
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	13,924,384	14,913,075
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,579,984	1,493,511
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	81,150	47,628
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	592,962	616,173
153	MaintenanceOfMeters (597) Maintenance of Meters	1,411,122	1,694,997
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	19,443	43,662
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	19,763,159	21,138,062
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	38,074,348	38,940,019
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision
160	MeterReadingExpenses (902) Meter Reading Expenses	1,279,878	1,313,720
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	8,586,694	7,782,099
162	UncollectibleAccounts (904) Uncollectible Accounts	2,493,740	1,656,016
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	53,055	47,387
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	12,413,367	10,799,222
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	3,705,679	3,459,332
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	1,004,139	1,123,871
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	117,112	79,969
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	4,826,930	4,663,172
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses
176	AdvertisingExpenses (913) Advertising Expenses	779,851	1,119,259
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	779,851	1,119,259
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	31,799,186	31,673,768
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	15,931,937	14,842,877
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	8,260,152	7,811,070
184	OutsideServicesEmployed (923) Outside Services Employed	7,949,210	8,190,730
185	PropertyInsurance (924) Property Insurance	3,447,380	3,045,613
186	InjuriesAndDamages (925) Injuries and Damages	13,880,167	10,883,643
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	(d) 25,787,597	22,191,172
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	3,686,267	3,240,980
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	484,058	327,308
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	(e) 15,262,542	14,579,531
193	RentsAdministrativeAndGeneralExpense (931) Rents	792,948	1,095,678
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	110,761,140	102,260,230
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	4,699,006	4,495,653
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	115,460,146	106,755,883
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	693,461,255	594,798,983

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	53,473	51,013
5	501 Fuel	36,168,095	34,302,960
6	502 Steam expenses	1,394,076	1,438,025
7	503 Steam from other sources		—
8	504 Less: Steam transferred-Cr		—
9	505 Electric expenses	403,193	536,048
10	506 Miscellaneous steam power expenses	2,839,102	2,379,298
11	507 Rents	—	—
12	509 Allowances		—
13	Total Operation	40,857,939	38,707,344
14	Maintenance
15	510 Maintenance supervision and engineering	270,438	521,165
16	511 Maintenance of structures	734,202	727,635
17	512 Maintenance of boiler plant	4,974,170	4,289,231
18	513 Maintenance of electric plant	531,996	685,935
19	514 Maintenance of miscellaneous steam plant	478,816	398,284
20	Total maintenance	6,989,622	6,622,250
21	Total Power Production Expenses-Steam Power	47,847,561	45,329,594
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	773,199	678,516
45	536 Water for power	1,010,210	949,611
46	537 Hydraulic expenses	3,726,277	3,654,685
47	538 Electric expenses	3,430,921	3,662,440
48	539 Miscellaneous hydraulic power generation expenses	3,025,811	2,903,753


49	540 Rents	824,957	808,039
50	Total Operation	12,791,375	12,657,044
51	C. Hydraulic Power Generation (continued)
52	Hydraulic Power Generation - Maintenance
53	541 Maintenance supervision and engineering	650,985	560,468
54	542 Maintenance of structures	507,445	715,688
55	543 Maintenance of reservoirs, dams and waterways	151,023	612,490
56	544 Maintenance of electric plant	1,036,087	1,228,566
57	545 Maintenance of miscellaneous hydraulic plant	211,995	215,886
58	Total Maintenance	2,557,535	3,333,098
59	Total power production expenses-hydraulic power	15,348,910	15,990,142

60	D. Other Power Generation
61	Operation
62	546 Operation supervision and engineering	485,709	437,140
63	547 Fuel	20,680,778	26,489,691
64	548 Generation expenses	3,917,087	3,832,823
65	549 Miscellaneous other power generation expenses	793,731	1,812,546
66	550 Rents	—	—
67	Total Operation	25,877,305	32,572,200
68	Maintenance
69	551 Maintenance supervision and engineering	—	—
70	552 Maintenance of structures	—	1,130
71	553 Maintenance of generating and electric plant	1,359,787	1,678,576
72	554 Maintenance of miscellaneous other power generating plant	94,667	60,566
73	Total Maintenance	1,454,454	1,740,272
74	Total power production expenses-other power	27,331,759	34,312,472
75	E. Other Power Supply Expenses
76	555 Purchased power	261,892,350	270,689,407
77	556 System control and load dispatching	—	—
78	557 Other expenses	62,910,866	(47,735,181)
79	Total other power supply exp	324,803,216	222,954,226
80	Total power production expenses	415,331,446	318,586,434
81	2. Transmission Expenses
82	Operation
83	560 Operation supervision and engineering	2,877,263	2,464,420
84	561 Load dispatching	—	—
85	561.1 Load dispatch-reliability	920,115	936,249
86	561.2 Load dispatch-monitor and operate transmission ssystem	878,169	965,381
87	561.3 Load dispatch-transmission service and scheduling	1,146,993	1,354,193
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	1,893,265	1,285,180
94	563 Overhead line expenses	775,402	1,163,275
95	564 Underground line expenses		—
96	565 Transmission of electricity by others	6,685,938	6,570,785
97	566 Miscellaneous transmission expense	161,951	153,589
98	567 Rents	1,032,912	1,076,543
99	Total Operation	16,372,008	15,969,615
100	Maintenance
101	568 Maintenance supervision and engineering	478,209	517,276
102	569 Maintenance of structures	22,653	48,248


103	569.1 Maintenance of computer hardware	1,312,307	1,442,191
104	569.2 Maintenance of computer software	13,110	2,874
105	569.3 Maintenance of communication equipment	—	—
106	569.4 Maintenance of miscellaneous regional transmission plant		—
107	570 Maintenance of station equipment	675,474	662,815
108	571 Maintenance of overhead lines	2,822,340	3,278,719
109	572 Maintenance of underground lines	—	—
110	573 Maintenance of miscellaneous transmission plant		—
111	Total Maintenance	5,324,093	5,952,123
112	Total transmission expenses	21,696,101	21,921,738

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	3,365,650	3,145,756
135	581 Load dispatching		—
136	582 Station expenses	1,370,551	1,284,768
137	583 Overhead line expenses	1,839,353	1,759,824
138	584 Underground line expenses	2,375,701	2,194,129
139	585 Street lighting and signal system expenses	68,421	113,330
140	586 Meter expenses	1,837,814	1,907,076
141	587 Customer installation expenses	1,636,331	1,720,348
142	588 Miscellaneous distribution expenses	2,587,793	2,510,632
143	589 Rents	72,610	81,788
144	Total Operation	15,154,224	14,717,651
145	Maintenance
146	590 Maintenance supervision and engineering	1,283,237	1,443,455
147	591 Maintenance of structures	19,450	28,996
148	592 Maintenance of station equipment	473,778	460,939
149	593 Maintenance of overhead lines	12,145,530	13,206,141
150	594 Maintenance of underground lines	1,363,971	1,348,635
151	595 Maintenance of line transformers	40,867	47,053
152	596 Maintenance of street lighting and signal systems	395,628	365,502
153	597 Maintenance of meters	1,199,117	1,317,093
154	598 Maintenance of miscellaneous distribution plant	—	—
155	Total Maintenance	16,921,578	18,217,814
156	Total distribution expenses	32,075,802	32,935,465


157	5. Customer Accounts Expenses
158	Operation
159	901 Supervision
160	902 Meter reading expenses	1,227,781	1,266,522
161	903 Customer records and collection expenses	7,461,259	6,705,862
162	904 Uncollectible accounts	2,240,210	1,300,105
163	905 Miscellaneous customer accounts expenses	—	(21)
164	Total customer accounts expenses	10,929,250	9,272,468

165	Customer Service and Informational Expenses
166	Operation
167	907 Supervision
168	908 Customer assistance expenses	2,668,960	2,451,956
169	909 Informational and instructional advertising expenses	862,987	978,485
170	910 Miscellaneous customer service and informational expenses	—	561,511
171	Total customer service and informational expenses	3,531,947	3,991,952
172	7. Sales Expenses
173	Operation
174	911 Supervision
175	912 Demonstrating and selling expenses
176	913 Advertising expenses	648,924	1,052,442
177	916 Miscellaneous sales expenses
178	Total sales expenses	648,924	1,052,442
179	8. Administrative and General Expenses
180	Operation
181	920 Administrative and general salaries	27,958,595	27,735,564
182	921 Office supplies and expenses	13,602,986	12,613,500
183	922 Less: Administrative expenses transferred - credits	6,971,581	6,531,731
184	923 Outside services employed	6,959,105	7,386,228
185	924 Property insurance	3,259,621	2,878,745
186	925 Injuries and damages	11,753,523	9,228,383
187	926 Employee pensions and benefits	22,523,233	19,197,833
188	927 Franchise requirements		—
189	928 Regulatory commission expenses	3,727,822	3,238,766
190	929 Less: Duplicate charges - credit		—
191	930.1 General advertising expenses	377,595	233,499
192	930.2 Miscellaneous general expenses	14,661,495	13,993,910
193	931 Rents	644,260	915,820
194	Total Operations	98,496,654	90,890,517
195	Maintenance
196	935 Maintenance of general plant	4,093,407	3,883,833
197	Total administrative and general expenses	102,590,061	94,774,350
198	Total Elec. Op. and Maint. Expns.	586,803,530	481,973,337

(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	729,331	735,685
5	501 Fuel	18,054,713	19,814,101
6	502 Steam expenses	1,376,881	1,299,624
7	503 Steam from other sources		—
8	504 Less: Steam transferred-Cr		—
9	505 Electric expenses	563,485	677,406
10	506 Miscellaneous steam power expenses	1,347,952	1,201,776
11	507 Rents	29,911	29,366
12	509 Allowances
13	Total Operation	22,102,273	23,757,958
14	Maintenance
15	510 Maintenance supervision and engineering	625,842	607,635
16	511 Maintenance of structures	328,576	340,835
17	512 Maintenance of boiler plant	2,325,108	2,528,659
18	513 Maintenance of electric plant	981,821	1,323,412
19	514 Maintenance of miscellaneous steam plant	556,304	573,086
20	Total maintenance	4,817,651	5,373,627
21	Total Power Production Expenses-Steam Power	26,919,924	29,131,585
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	133,892	285,048
63	547 Fuel	5,275,105	7,234,698
64	548 Generation expenses	4,749,809	4,192,889
65	549 Miscellaneous other power generation expenses	509,030	593,589
66	550 Rents	—	—
67	Total Operation	10,667,836	12,306,224
68	Maintenance
69	551 Maintenance supervision and engineering	63,598	50,511
70	552 Maintenance of structures	105,114	156,974
71	553 Maintenance of generating and electric plant	1,186,171	763,021
72	554 Maintenance of miscellaneous other power generating plant	52,600	14,978
73	Total Maintenance	1,407,483	985,484
74	Total power production expenses-other power	12,075,319	13,291,708
75	E. Other Power Supply Expenses
76	555 Purchased power	19,557,361	18,710,205
77	556 System control and load dispatching	348,013	304,468
78	557 Other expenses	4,903,905	8,668,714
79	Total other power supply exp	24,809,279	27,683,387
80	Total power production expenses	63,804,523	70,106,681
81	2. Transmission Expenses
82	Operation
83	560 Operation supervision and engineering	184,127	175,189
84	561 Load dispatching	65,111	63,839
85	561.1 Load dispatch-reliability	—	—
86	561.2 Load dispatch-monitor and operate transmission system	—	—
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	105,401	94,637
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	191,865	329,647
94	563 Overhead line expenses	186,678	196,531
95	564 Underground line expenses		—
96	565 Transmission of electricity by others	19,298,804	19,967,717
97	566 Miscellaneous transmission expense	73,602	89,373
98	567 Rents	17,295	24,811
99	Total Operation	20,125,883	20,944,744
100	Maintenance
101	568 Maintenance supervision and engineering	93,684	73,337
102	569 Maintenance of structures	12,698	13,089
103	569.1 Maintenance of computer hardware	—	—
104	569.2 Maintenance of computer software	—	—


105	569.3 Maintenance of communication equipment	—	—
106	569.4 Maintenance of miscellaneous regional transmission plant
107	570 Maintenance of station equipment	16,542	85,051
108	571 Maintenance of overhead lines	270,123	323,848
109	572 Maintenance of underground lines	188	370
110	573 Maintenance of miscellaneous transmission plant
111	Total Maintenance	393,235	495,695
112	Total transmission expenses	20,519,118	21,440,439

113	3. Regional Market Expenses
114	Operation
115	575.1 Operation supervision
116	575.2 Day-ahead and real-time market facilitation	388,799	326,293
117	575.3 Transmission rights market facilitation		—
118	575.4 Capacity market facilitation		—
119	575.5 Ancillary services market facilitation	111,085	93,227
120	575.6 Market monitoring and compliance	55,543	46,613
121	575.7 Market facilitation, monitoring and compliance services
122	575.8 Rents
123	Total Operation	555,427	466,133
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	514,270	457,427
135	581 Load dispatching		—
136	582 Station expenses	252,665	233,422
137	583 Overhead line expenses	425,915	373,768
138	584 Underground line expenses	536,374	665,205
139	585 Street lighting and signal system expenses	43,509	49,729
140	586 Meter expenses	333,297	462,917
141	587 Customer installation expenses	176,103	207,410
142	588 Miscellaneous distribution expenses	874,831	634,430
143	589 Rents	—	—
144	Total Operation	3,156,964	3,084,308
145	Maintenance
146	590 Maintenance supervision and engineering	244,074	204,364
147	591 Maintenance of structures		—
148	592 Maintenance of station equipment	133,575	191,261
149	593 Maintenance of overhead lines	1,778,854	1,706,934
150	594 Maintenance of underground lines	216,013	144,876
151	595 Maintenance of line transformers	40,283	575
152	596 Maintenance of street lighting and signal systems	197,334	250,671
153	597 Maintenance of meters	212,006	377,904
154	598 Maintenance of miscellaneous distribution plant	19,443	43,662
155	Total Maintenance	2,841,582	2,920,247
156	Total distribution expenses	5,998,546	6,004,555
157	5. Customer Accounts Expenses
158	Operation


159	901 Supervision
160	902 Meter reading expenses	52,098	47,199
161	903 Customer records and collection expenses	1,125,435	1,076,237
162	904 Uncollectible accounts	253,530	355,912
163	905 Miscellaneous customer accounts expenses	53,054	47,408
164	Total customer accounts expenses	1,484,117	1,526,756

165	Customer Service and Informational Expenses
166	Operation
167	907 Supervision
168	908 Customer assistance expenses	1,036,719	1,007,375
169	909 Informational and instructional advertising expenses	141,152	145,386
170	910 Miscellaneous customer service and informational expenses	117,112	79,970
171	Total customer service and informational expenses	1,294,983	1,232,731
172	7. Sales Expenses
173	Operation
174	911 Supervision
175	912 Demonstrating and selling expenses
176	913 Advertising expenses	130,928	66,816
177	916 Miscellaneous sales expenses
178	Total sales expenses	130,928	66,816
179	8. Administrative and General Expenses
180	Operation
181	920 Administrative and general salaries	3,840,591	3,938,203
182	921 Office supplies and expenses	2,328,951	2,229,377
183	922 Less: Administrative expenses transferred - credits	1,288,571	1,279,340
184	923 Outside services employed	990,106	804,502
185	924 Property insurance	187,759	166,868
186	925 Injuries and damages	2,126,644	1,655,258
187	926 Employee pensions and benefits	3,264,364	2,993,341
188	927 Franchise requirements		—
189	928 Regulatory commission expenses	(41,555)	2,213
190	929 Less: Duplicate charges - credit		—
191	930.1 General advertising expenses	106,462	93,810
192	930.2 Miscellaneous general expenses	601,047	585,621
193	931 Rents	148,689	179,857
194	Total Operations	12,264,487	11,369,710
195	Maintenance
196	935 Maintenance of general plant	605,599	611,823
197	Total administrative and general expenses	12,870,086	11,981,533
198	Total Elec. Op. and Maint. Expns.	106,657,725	112,825,646


Account 557 Other Expenses			Amount

Account 557 Total Expense			63,078,366

Less: Variable Supply Costs			61,814,117

Amount to disclose in FERC Template page WP_FCR			1,264,249

Account 557 Fixed costs:
Wind Procurement Costs			158,343
OATI-Default Electric Supply			—
Schedulers-Default Electric			—
Res Acq EL-Supply Operations			749,770
Mktg Sup EL-Supply Operation			216,554
Gen Adm Oth Power Sup			38,979
Eng Sup Plan-Other Power Sup			37,966
Mktg Supply-Other Power Supp			62,637
Subtotal			1,264,249

(d) Concept: EmployeePensionsAndBenefits


Plan Name	MT Medical (Regulatory)
Country	US
Fiscal year ending on	Dec 31, 2023
A. Net Periodic Benefit Cost
1. Service cost	$	272,534
2. Interest cost	553,883
3. Expected return on plan assets	(1,096,381)
4. Amortization of initial net obligation (asset)	—
5. Amortization of prior service cost	116,071
6. Amortization of net (gain) loss	629,161
7. Curtailment (gain)/loss recognized	—
8. Settlement (gain)/loss recognized	—
9. Special termination benefit recognized	—
10. Net periodic benefit cost	$	475,268

Electric Only	255,509

(e) Concept: MiscellaneousGeneralExpenses


	Montana Operations	South Dakota Operations	Total 930.2
Universal System Benefits Charge	10,425,797	—	10,425,797
Our Portion of Shared Ownership Gen	1,626,479	—	1,626,479
	12,052,276	—	12,052,276

Board of Directors Fees	1,775,857	286,502	2,062,359
Shareholder Expense	83,438	13,458	96,896
Industry & Association Dues	389,621	235,991	625,612
Amortization of upfront fees	372,197	60,089	432,286
Human Resources general expenses (non-labor and not provided for elsewhere)	17,016	5,777	22,793
Miscellaneous	(28,910)	(770)	(29,680)
	2,609,219	601,047	3,210,266

Total Account 930.2	14,661,495	601,047	15,262,542

Montana Operations Miscellaneous General Expenses account 930.2 includes $126,180 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:

12/31/2023

Year/Period of Report

End of:

2023

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					490,738					52,733,966	(a) 9,705	52,724,261
5	Colstrip Energy Ltd/Montana One (TIER II QF)	LU					306,168					23,345,760	(b) 4,822	23,340,938
6	Hydrodynamics - Strawberry Creek (TIER II QF)	LU					376					24,407	(c) 618	23,789
7	Pine Creek (TIER II QF)	LU					1,232					102,703	(d) 5,422	97,281
8	Ross Creek Hydro (TIER II QF)	LU					1,696					63,566	(e) 2,840	60,726
9	State of Montana-DNRC / Broadwater Dam (TIER II QF)	LU					39,318					5,504,077	(f) 5,088	5,498,989
10	NON TIER II QF-1 CONTRACTS
11	71 Ranch (NON TIER II QF-1)	LU					10,010					563,079		563,079
12	Big Timber Wind (NON TIER II QF-1)	LU					76,384					3,464,427		3,464,427
13	Boulder Hydro (NON TIER II QF-1)	LU					1,181					68,397		68,397
14	Broadview East/Two Dot (NON TIER II QF-1)	LU					4,198					212,978		212,978
15	Cycle Horseshoe Bend (NON TIER II QF-1)	LU					4,265					203,016		203,016
16	DA Wind (NON TIER II QF-1)	LU					9,407					529,289		529,289
17	Fairfield Wind (NON TIER II QF-1)	LU					25,760					1,846,504	(g)(h) 93,991	1,752,513
18	Flint Creek Hydro (NON TIER II QF-1)	LU					10,960					767,605		767,605
19	Gordon Butte Wind (NON TIER II QF-1)	LU					37,246					2,577,767		2,577,767
20	Greenfield (NON TIER II QF-1)	LU					83,749					4,164,485		4,164,485
21	Hanover Hydro (NON TIER II QF-1)	LU					242					14,849		14,849
22	Lower South Fork (NON TIER II QF-1)	LU					647					33,550		33,550
23	Musselshell Wind 1 (NON TIER II QF-1)	LU					19,483					1,348,418		1,348,418
24	Musselshell Wind 2 (NON TIER II QF-1)	LU					23,624					1,635,004		1,635,004
25	Oversight Resources (NON TIER II QF-1)	LU					9,807					548,735		548,735
26	Pony Hydro (NON TIER II QF-1)	LU					458					19,032		19,032
27	South Dry Creek (NON TIER II QF-1)	LU					2,908					124,695		124,695
28	South Peak Wind (NON TIER II QF-1)	LU					248,245					5,654,109		5,654,109
29	Stillwater Wind (NON TIER II QF-1)	LU					256,339					9,655,964		9,655,964
30	Strawberry Creek (NON TIER II QF-1)	LU					419					31,767		31,767
31	Wisconsin Creek (NON TIER II QF-1)	LU					618					17,668		17,668
32	NON TIER II SOLAR QF CONTRACTS
33	River Bend Solar (NON TIER II SOLAR QF)	LU					3,641					237,199		237,199
34	Green Meadow Solar (NON TIER II SOLAR QF)	LU					5,498					359,592		359,592
35	South Mills Solar 1 (NON TIER II SOLAR QF)	LU					5,941					386,915		386,915
36	Black Eagle Solar (NON TIER II SOLAR QF)	LU					5,285					343,333		343,333
37	Great Divide Solar LLC (NON TIER II SOLAR QF)	LU					5,894					384,169		384,169
38	Magpie Solar LLC (NON TIER II SOLAR QF)	LU					5,774					378,070		378,070
39	Montana Sun, LLC (NON TIER II SOLAR QF)	LU					152,731					6,389,166		6,389,166
40	Apex Solar LLC (test energy) (NON TIER II SOLAR QF)	LU					24,555					437,686		437,686
41	Apex Solar LLC (commercial energy) (NON TIER II SOLAR QF)	LU					53,437					1,983,555		1,983,555
42	RESERVE SHARING TRANSACTIONS:
43	AVISTA CORPORATION (RESERVE SHARING)	LF	Reserve Energy Services				8					607		607
44	AVANGRID RENEWABLES, LLC (RESERVE SHARING)	LF	Reserve Energy Services				16					1,093		1,093
45	BONNEVILLE POWER ADMINISTRATION (RESERVE SHARING)	LF	Reserve Energy Services				288					19,488		19,488
46	CHELAN COUNT PUD (RESERVE SHARING)	LF	Reserve Energy Services				15					1,008		1,008
47	GRIDFORCE ENERGY MANAGEMENT (RESERVE SHARING)	LF	Reserve Energy Services				27					1,891		1,891
48	DOUGLAS COUNTY PUD (RESERVE SHARING)	LF	Reserve Energy Services				4					174		174
49	GRANT COUNTY PUD (RESERVE SHARING)	LF	Reserve Energy Services				25					1,544		1,544
50	PACIFICORP (RESERVE SHARING)	LF	Reserve Energy Services				66					4,498		4,498
51	PORTLAND GENERAL ELECTRIC COMPANY (RESERVE SHARING)	LF	Reserve Energy Services				61					4,067		4,067
52	PUGET SOUND ENERGY (RESERVE SHARING)	LF	Reserve Energy Services				20					1,284		1,284
53	SEATTLE CITY LIGHT (RESERVE SHARING)	LF	Reserve Energy Services				31					1,954		1,954
54	TACOMA POWER (RESERVE SHARING)	LF	Reserve Energy Services				16					1,005		1,005
55	WESTERN AREA POWER ADMINISTATION (RESERVE SHARING)	LF	Reserve Energy Services				2					53		53
56	EXCHANGES:
57	Pacificorp - Costrip Loss/Startup (EXCHANGES)	EX	RS 190						2,866	2,855		1,496		1,496
58	Talen Energy Marketing, LLC - Startup (EXCHANGES)	EX	RS 190						4,325	4,283		12		12
59	Portland General Electric - Colstrip Loss/Startup (EXCHANGES)	EX	RS 190						5,793	5,709		4,515		4,515
60	Puget Sound Energy - Colstrip Units 3&4 Startup (EXCHANGES)	EX	RS 190						7,224	7,137		4,609		4,609
61	Northwestern Energy Colstrip Unit 4 - Startup (EXCHANGES)	EX	RS 190						4,331	4,283		2,371		2,371
62	AVISTA Corporation - Colstrip Loss/Startup (EXCHANGES)	EX	RS 190						4,335	4,283		1,778		1,778
63	PURCHASED POWER SUPPLY:
64	Avista Corporation (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				18,538					3,344,240		3,344,240
65	Basin Electric Power Cooperative (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				1,200					453,424		453,424
66	Basin Power Plant (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				8,760					6,809,511		6,809,511
67	Black Hills Power Inc (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				0
68	Bonneville Power Administration (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				26,770					4,403,648		4,403,648
69	Clatskanie Peoples Utility District - Electric (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				1,613					183,393		183,393
70	Conoco Phillips Corp (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				2,546					354,055		354,055
71	Shell Energy North America (US), L.P. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				10,267					1,317,134		1,317,134
72	Dynasty Power, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				2,576					519,025		519,025
73	Constellation Energy Generation, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				1,509					111,160		111,160
74	EDF Trading North America, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				23,626					4,502,470		4,502,470
75	Energy Keepers, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				25,382					6,255,645		6,255,645
76	Eugene Water & Electric Board (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				3,921					455,031		455,031
77	Guzman Energy, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				4,879					643,359		643,359
78	Avangrid Renewables, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				13,398					1,678,240		1,678,240
79	Heartland Generation LTD (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				19,797					17,971,216		17,971,216
80	Idaho Power Company (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				1,670					164,420		164,420
81	Invenergy Energy Marketing LLC-Electric (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				417,335					14,064,877		14,064,877
82	Macquarie Energy LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				8,674					1,625,270		1,625,270
83	Morgan Stanley Capital Group, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				417,465					55,283,866		55,283,866
84	PacifiCorp (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				2,030					108,691		108,691
85	Portland General Electric (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				48,241					6,701,278		6,701,278
86	Powerex Corp. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				242,110					34,374,821		34,374,821
87	Talen Energy Marketing, LLC (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				0
88	Puget Sound Energy (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				28,610					3,637,128		3,637,128
89	Rainbow Energy Marketing Corporation (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				6,010					1,220,238		1,220,238
90	Seattle City Light (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				7,487					1,461,055		1,461,055
91	Tacoma Power (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				5,931					1,372,690		1,372,690
92	The Energy Authority, Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				70,967					10,122,111		10,122,111
93	Tiber Montana, LLC (PURCHASED POWER SUPPLY)	LU	Market-Based Rate Tariff				40,714					2,106,705		2,106,705
94	TransAlta Energy Marketing (US), Inc. (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				19,017					3,883,492		3,883,492
95	Turnbull Hydro, LLC (PURCHASED POWER SUPPLY)	LU	Market-Based Rate Tariff				22,909					1,643,701		1,643,701
96	Tenaska Power (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				635					144,475		144,475
97	Western Area Power Administation (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				653					9,605		9,605
98	Vitol Inc-Electric (PURCHASED POWER SUPPLY)	SF	Market-Based Rate Tariff				80					18,750		18,750
99	California Independent System Operator - EIM Transmission (PURCHASED POWER SUPPLY)	SF	CAISO									5,398,776		5,398,776
100	California Independent System Operator - EIM Supply (PURCHASED POWER SUPPLY)	SF	CAISO									29,367,309		29,367,309
101	Estimate Energy (PURCHASED POWER SUPPLY)											27,167,291		27,167,291
102	SOUTH DAKOTA PURCHASES
103	WAPA (Various) (SOUTH DAKOTA PURCHASES)	OS	29				0					130,115		130,115
104	Lincoln Energy Services (SOUTH DAKOTA PURCHASES)	OS	29								720,000			720,000
105	Southwest Power Pool (SOUTH DAKOTA PURCHASES)	OS	SPP RTO				314,598					5,551,919		5,551,919
106	Titan Wind (PPA Wind #1) (SOUTH DAKOTA PURCHASES)	LU					79,950					5,867,628		5,867,628
107	Oak Tree (PPA Wind #2) (SOUTH DAKOTA PURCHASES)	LU					68,261					3,497,079		3,497,079
108	Aurora Wind (SOUTH DAKOTA PURCHASES)	LU					71,174					1,963,058		1,963,058
109	Brule Wind (SOUTH DAKOTA PURCHASES)	LU					68,663					1,799,932		1,799,932
110	Codington Clark Electric (SOUTH DAKOTA PURCHASES)	OS										11,050		11,050
111	MidAmerican Energy (SOUTH DAKOTA PURCHASES)	OS										18,435		18,435
112	Terex (SOUTH DAKOTA PURCHASES)	OS											(i) 1,855	1,855
113	Rounding						6					2	1	3
15	TOTAL						4,036,773	0	28,874	28,550	720,000	280,854,051	124,340	281,449,711

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment and annual interconnect fee.

(b) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment and annual interconnect fee.

(d) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment and annual interconnect fee.

(e) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment and annual interconnect fee.

(f) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment and annual interconnect fee.

(g) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment and annual interconnect fee.

(h) Concept: OtherChargesOfPurchasedPower

Annual capacity and energy adjustment and annual interconnect fee.

(i) Concept: OtherChargesOfPurchasedPower

REC credit sales

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	39,125	39,125	213,199			213,199
3	Aspen Air U.S., LLC	Talen Energy	Aspen Air Corporation	FNO	Montana OATT	Colstrip	Billings, MT	11	49,966	49,966	257,279			257,279
4	Barretts Minerals, Inc.	Energy Keepers inc.	Barretts Minerals, Inc.	FNO	Montana OATT	Kerr	Dillon, MT	6	27,798	27,798	149,958			149,958
5	Beartooth Electric Cooperative, Inc.	WAPA & Energy Keepers Inc.	Beartooth Electric Cooperative, Inc.	FNO	Montana OATT	Fort Peck & Kerr	Various in Montana	18	86,742	86,742	655,561			655,561
6	Benefis Health Systems	Energy Keepers inc.	Benefis Health Systems	FNO	Montana OATT	Kerr	Various in Montana	7	34,206	34,206	208,871			208,871
7	Big Horn County Electric Coop. Inc.	WAPA	Big Horn County Electric Coop. Inc.	FNO	Montana OATT	Various & Great Falls	Various in Montana	18	71,147	71,147	513,828			513,828
8	Bonneville Power Administration	BPA	Bonneville Power Administration	FNO	Montana OATT	BPAT.NWMT	Various in Montana	185	907,252	907,252	6,371,197			6,371,197
9	Basin Electric Power Cooperative	Morgan Stanley, WAPA, Talen Energy	Basin Electric Power Cooperative	FNO	Montana OATT	Various in Montana	Various NWMT & WAUW	181	890,823	890,823	5,780,721			5,780,721
10	Basin Electric Power Cooperative	Basin Electric & WAPA	Basin Electric Power Cooperative	FNO	Montana OATT	BPAT.NWMT & Great Falls	Various NWMT & WAUW	15	78,898	78,898	515,950			515,950
11	CHS, Inc.	Morgan Stanley	CHS, Inc.	FNO	Montana OATT	MATL.NWMT & BPAT.NWMT	Various in Montana	58	337,235	337,235	1,883,138			1,883,138
12	City of Great Falls	Energy Keepers Inc.	City of Great Falls	FNO	Montana OATT	Kerr	Various in Montana	6	19,679	19,679	107,350			107,350
13	Talen Montana, LLC	Avista Energy	Colstrip Steam Electric Station	FNO	Montana OATT	Colstrip	Nichols Pump Sub	10	33,551	33,551	160,760			160,760
14	Atlas Power, LLC	Portland General Electric	Atlas Power, LLC	FNO	Montana OATT	Colstrip	Butte, MT	75	332,441	332,441	1,619,128			1,619,128
15	Phillips 66 Company	Shell Energy	Phillips 66 Company	FNO	Montana OATT	BPAT.NWMT	Various in Montana	70	483,916	483,916	2,347,604			2,347,604
16	Par Montana, LLC	Talen Energy	Par Montana, LLC	FNO	Montana OATT	Colstrip	Billings, MT	35	253,688	253,688	1,236,567			1,236,567
17	General Mills Operations, LLC	Talen Energy	General Mills Operations, LLC	FNO	Montana OATT	Colstrip	Great Falls, MT	4	20,252	20,252	116,534			116,534
18	Great Falls Public Schools	Energy Keepers Inc.	Great Falls Public Schools	FNO	Montana OATT	Kerr	Great Falls, MT	3	9,888	9,888	61,694			61,694
19	GCC Three Forks, LLC	Energy Keepers Inc., GCC Three Forks	GCC Three Forks, LLC	FNO	Montana OATT	Kerr & GCC	Three Forks, MT	8	36,043	36,043	194,058			194,058
20	Magris Talc USA, Inc.	Energy Keepers Inc.	Magris Talc USA, Inc.	FNO	Montana OATT	Kerr	Three Forks, MT	6	26,194	26,194	154,825			154,825
21	DFA Dairy Brands Fluid, LLC	Talen Energy	DFA Dairy Brands Fluid, LLC	FNO	Montana OATT	Colstrip	Various in Montana	2	5,959	5,959	34,072			34,072
22	Calumet Refining, LLC	Talen Energy	Calumet Montana Refining Company, Inc.	FNO	Montana OATT	Colstrip	Great Falls, MT	25	129,822	129,822	573,817			573,817
23	Montana Resources	Energy Keepers, Inc.	Montana Resources	FNO	Montana OATT	BPAT.NWMT & Kerr	Butte, MT	50	353,585	353,585	1,811,830			1,811,830
24	REC Silicon Company	Morgan Stanley	REC Silicon Company	FNO	Montana OATT	Hardin	Butte, MT	117	591,746	591,746	2,868,566			2,868,566
25	Roseburg Forest Products Company	Shell Energy	Roseburg Forest Products Company	FNO	Montana OATT	BPAT.NWMT	Missoula, MT	8	44,607	44,607	243,088			243,088
26	Sibanye-Stillwater	Various	Stillwater Mining Company	FNO	Montana OATT	As Available	Various in Montana	46	289,842	289,842	1,425,931			1,425,931
27	Town of Philipsburg	Town of Philipsburg	Town of Philipsburg	FNO	Montana OATT	Philipsburg Substation	Philipsburg, MT		616	616	4,182			4,182
28	Western Area Power Administration	WAPA	Western Area Power Administration	FNO	Montana OATT	Crossover	Various NWMT & WAUW	4	8	8	28,914			28,914
29	Montana State University - Bozeman	WAPA	Montana State University - Bozeman	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	15,966	15,966	89,943			89,943
30	Western Area Power Administration	WAPA	Malmstrom Air Force Base	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	28,888	28,888	153,790			153,790
31	MONTANA POINT-TO-POINT
32	Altop Energy Trading LLC	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER		12	12		65		65
33	Altop Energy Trading LLC	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		1,037	1,037		5,621		5,621
34	Avangrid Renewables, LLC	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		1,800	1,800		8,325		8,325
35	Avista Corporation	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		35,748	35,748		187,265		187,265
36	Avista Corporation	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		125,482	125,482		629,536		629,536
37	Avista Corporation	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	COLSTRIP		138	138		748		748
38	Avista Corporation	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		2,668	2,668		13,015		13,015
39	Avista Corporation	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		200	200		926		926
40	Basin Electric Power Cooperative	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	GREATFALLS		39	39		181		181
41	Basin Electric Power Cooperative	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		725	725		3,428		3,428
42	Basin Electric Power Cooperative	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS		1,184	1,184		6,217		6,217
43	Basin Electric Power Cooperative	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		13	13		60		60
44	Basin Electric Power Cooperative	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM		5	5		27		27
45	Basin Electric Power Cooperative	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		101	101		547		547
46	Basin Electric Power Cooperative	NWMT	WAUW	NF	MONTANA OATT	COLSTRIP	GREATFALLS		147	147		711		711
47	Basin Electric Power Cooperative	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	GREATFALLS		105	105		569		569
48	Basin Electric Power Cooperative	PPW	NWMT	NF	MONTANA OATT	MLCK	NWMT.SYSTEM		67	67		310		310
49	Basin Electric Power Cooperative	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM		138	138		639		639
50	Basin Electric Power Cooperative	PPW	NWMT	SFP	MONTANA OATT	BRDY	NWMT.SYSTEM		600	600		2,775		2,775
51	Basin Electric Power Cooperative	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		7,176	7,176		37,998		37,998
52	Basin Electric Power Cooperative	PPW	PPW	NF	MONTANA OATT	BRDY	MLCK		67	67		310		310
53	Basin Electric Power Cooperative	PPW	PPW	NF	MONTANA OATT	COLSTRIP	MLCK		375	375		2,033		2,033
54	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	BRDY	GREATFALLS		245	245		1,145		1,145
55	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		17,272	17,272		93,053		93,053
56	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	YTP	GREATFALLS		360	360		1,951		1,951
57	Basin Electric Power Cooperative	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER		10,608	10,608		55,313		55,313
58	Basin Electric Power Cooperative	PPW	WAPA	SFP	MONTANA OATT	YTP	GREATFALLS		1,176	1,176		5,432		5,432
59	Basin Electric Power Cooperative	WAPA	NWMT	NF	MONTANA OATT	GREATFALLS	NWMT.SYSTEM		27	27		146		146
60	Basin Electric Power Cooperative	WAPA	NWMT	SFP	MONTANA OATT	CROSSOVER	NWMT.SYSTEM		60,921	60,921		300,415		300,415
61	Basin Electric Power Cooperative	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		337	337		1,826		1,826
62	Basin Electric Power Cooperative	WAPA	WAPA	LFP	MONTANA OATT	CROSSOVER	GREATFALLS	31	271,560	271,560	1,374,889			1,374,889
63	Basin Electric Power Cooperative	WAPA	WAPA	NF	MONTANA OATT	CROSSOVER	GREATFALLS		20	20		108		108
64	Bonneville Power Administration	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		1,510	1,510		8,184		8,184
65	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	ANTE		42	42		199		199
66	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		119	119		617		617
67	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		44	44		238		238
68	Bonneville Power Administration	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS		251	251		1,206		1,206
69	Bonneville Power Administration	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		1	1		5		5
70	Bonneville Power Administration	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	ANTE		1	1		5		5
71	Bonneville Power Administration	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		1	1		5		5
72	Brookfield Renewable Trading and Marketing LP	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		175	175		810		810
73	Brookfield Renewable Trading and Marketing LP	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		156	156		743		743
74	Brookfield Renewable Trading and Marketing LP	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		52	52		241		241
75	Brookfield Renewable Trading and Marketing LP	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		46	46		213		213
76	Brookfield Renewable Trading and Marketing LP	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		18	18		83		83
77	Clearwater Energy Resources, LLC	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		155,736	155,736		849,960		849,960
78	ConocoPhillips	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		72	72		390		390
79	ConocoPhillips	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		64	64		296		296
80	ConocoPhillips	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		88	88		407		407
81	CP Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		7,035	7,035		37,807		37,807
82	CP Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		338	338		1,825		1,825
83	CP Energy Marketing (US) Inc.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		60	60		325		325
84	CP Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		39,465	39,465		186,718		186,718
85	CP Energy Marketing (US) Inc.	NWMT	BPAT	SFP	MONTANA OATT	MATL.NWMT	BPAT.NWMT		1,752	1,752		8,103		8,103
86	CP Energy Marketing (US) Inc.	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM		5	5		27		27
87	CP Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY		165	165		764		764
88	CP Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF		100	100		463		463
89	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	BRDY		684	684		3,616		3,616
90	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	JEFF		24,184	24,184		120,483		120,483
91	Dynasty Power Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT		40	40		185		185
92	Dynasty Power Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	JEFF		299	299		1,621		1,621
93	Dynasty Power Inc.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		50	50		271		271
94	Dynasty Power Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		20	20		93		93
95	Dynasty Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		253	253		1,171		1,171
96	Dynasty Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		700	700		3,794		3,794
97	Dynasty Power Inc.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		167	167		905		905
98	Dynasty Power Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		4,123	4,123		21,772		21,772
99	Dynasty Power Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	GTFALLSNWMT		112	112		607		607
100	Dynasty Power Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	NWMT.SYSTEM		328	328		1,778		1,778
101	Dynasty Power Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		78	78		361		361
102	Dynasty Power Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		2,536	2,536		11,730		11,730
103	Dynasty Power Inc.	PPW	NWMT	NF	MONTANA OATT	BRDY	GTFALLSNWMT		14	14		76		76
104	Dynasty Power Inc.	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM		51	51		276		276
105	Dynasty Power Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		6,167	6,167		28,667		28,667
106	Dynasty Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		3,565	3,565		16,503		16,503
107	Dynasty Power Inc.	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP		408	408		1,887		1,887
108	EDF Trading North America, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		9,334	9,334		46,861		46,861
109	EDF Trading North America, LLC	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		9,073	9,073		46,882		46,882
110	EDF Trading North America, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	COLSTRIP		229	229		1,241		1,241
111	EDF Trading North America, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM		1,368	1,368		7,415		7,415
112	EDF Trading North America, LLC	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		188	188		870		870
113	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP		2,238	2,238		11,343		11,343
114	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT		70	70		379		379
115	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		2,524	2,524		12,883		12,883
116	EDF Trading North America, LLC	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		1,915	1,915		9,659		9,659
117	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		90,218	90,218		469,970		469,970
118	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		24	24		130		130
119	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		21	21		114		114
120	EDF Trading North America, LLC	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		22,368	22,368		119,735		119,735
121	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP		4,516	4,516		23,248		23,248
122	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT		933	933		4,716		4,716
123	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	NWMT.SYSTEM		42	42		228		228
124	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	CROOKEDFALLS	NWMT.SYSTEM		1	1		5		5
125	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	HARDIN	COLSTRIP		35	35		190		190
126	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	JUDITHGAP	COLSTRIP		72	72		390		390
127	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	NWMTIMBALANC	NWMT.SYSTEM		530	530		2,866		2,866
128	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		13,862	13,862		66,871		66,871
129	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF		835	835		3,866		3,866
130	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		235	235		1,191		1,191
131	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	BRDY		9,720	9,720		48,565		48,565
132	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	JEFF		3,504	3,504		16,206		16,206
133	EDF Trading North America, LLC	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER		40	40		185		185
134	EDF Trading North America, LLC	PACE	NWMT	NF	MONTANA OATT	BRDY	COLSTRIP		319	319		1,729		1,729
135	EDF Trading North America, LLC	PPW	NWMT	NF	MONTANA OATT	BRDY	GTFALLSNWMT		20	20		108		108
136	EDF Trading North America, LLC	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM		1,492	1,492		8,087		8,087
137	Energy Keepers Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	ANTE		600	600		3,250		3,250
138	Energy Keepers Inc.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		600	600		2,775		2,775
139	Energy Keepers Inc.	BPAT	AVA	SFP	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		600	600		2,775		2,775
140	Energy Keepers Inc.	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		119,232	119,232		637,470		637,470
141	Energy Keepers Inc.	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		480	480		2,602		2,602
142	Energy Keepers Inc.	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT		891	891		4,829		4,829
143	Energy Keepers Inc.	NWMT	AVA	SFP	MONTANA OATT	KERR	AVAT.NWMT		2,328	2,328		11,755		11,755
144	Energy Keepers Inc.	NWMT	BPAT	LFP	MONTANA OATT	KERR	BPAT.NWMT	40	350,400	350,400	1,774,050			1,774,050
145	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT		1,221	1,221		6,585		6,585
146	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		480	480		2,600		2,600
147	Energy Keepers Inc.	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		1,920	1,920		8,975		8,975
148	Energy Keepers Inc.	NWMT	BPAT	SFP	MONTANA OATT	KERR	BPAT.NWMT		61,473	61,473		301,381		301,381
149	Energy Keepers Inc.	NWMT	NWMT	NF	MONTANA OATT	KERR	GTFALLSNWMT		288	288		1,560		1,560
150	Energy Keepers Inc.	NWMT	PACE	LFP	MONTANA OATT	KERR	BRDY	50	438,000	438,000	2,217,562			2,217,562
151	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	ANTE		1,080	1,080		5,850		5,850
152	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	BRDY		234	234		1,083		1,083
153	Energy Keepers Inc.	NWMT	PACE	SFP	MONTANA OATT	KERR	BRDY		8,448	8,448		39,511		39,511
154	Energy Keepers Inc.	NWMT	PACE	SFP	MONTANA OATT	KERR	YTP		1,776	1,776		8,214		8,214
155	Energy Keepers Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	ANTE		720	720		3,900		3,900
156	Energy Keepers Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF		175	175		949		949
157	Energy Keepers Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		300	300		1,389		1,389
158	Energy Keepers Inc.	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP		9,000	9,000		41,625		41,625
159	Energy Keepers Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		686	686		3,718		3,718
160	Energy Keepers Inc.	PPW	BPAT	SFP	MONTANA OATT	BRDY	BPAT.NWMT		192	192		1,040		1,040
161	Guzman Energy, LLC	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		140	140		648		648
162	Guzman Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY		401	401		2,173		2,173
163	Guzman Energy, LLC	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		36	36		167		167
164	Guzman Energy, LLC	BPAT	BPAT	NF	MONTANA OATT	BPAT.NWMT	BPAT.NWMT		70	70		379		379
165	Guzman Energy, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		25	25		136		136
166	Guzman Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		76	76		412		412
167	Guzman Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		31	31		168		168
168	Guzman Energy, LLC	NWMT	NWMT	NF	MONTANA OATT	CLEARWATER	TOWNSEND		1	1		5		5
169	Guzman Energy, LLC	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT		300	300		1,389		1,389
170	Guzman Energy, LLC	PPW	AVA	SFP	MONTANA OATT	BRDY	AVAT.NWMT		672	672		3,632		3,632
171	Guzman Energy, LLC	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		309,000	309,000		1,502,075		1,502,075
172	Guzman Energy, LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		326	326		1,731		1,731
173	Guzman Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	BRDY	BPAT.NWMT		648	648		3,510		3,510
174	Guzman Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		163,820	163,820		813,625		813,625
175	Guzman Energy, LLC	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM		150	150		813		813
176	Guzman Energy, LLC	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		1,729	1,729		9,245		9,245
177	Guzman Energy, LLC	PPW	WAPA	NF	MONTANA OATT	YTP	GREATFALLS		25	25		136		136
178	Guzman Energy, LLC	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT		675	675		3,658		3,658
179	Guzman Energy, LLC	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT		6,048	6,048		27,936		27,936
180	Guzman Energy, LLC	WAPA	NWMT	NF	MONTANA OATT	GREATFALLS	NWMT.SYSTEM		110	110		596		596
181	Guzman Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		8,187	8,187		43,078		43,078
182	Guzman Energy, LLC	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY		176	176		954		954
183	Guzman Energy, LLC	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP		2,400	2,400		13,000		13,000
184	Guzman Energy, LLC	WAPA	WAPA	NF	MONTANA OATT	GREATFALLS	CROSSOVER		25	25		136		136
185	Heartland Generation Ltd	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		1,340	1,340		7,259		7,259
186	Heartland Generation Ltd	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		480	480		2,600		2,600
187	Iberdrola Renewables Inc.	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		55	55		255		255
188	Iberdrola Renewables Inc.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		208	208		963		963
189	Iberdrola Renewables Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		192	192		889		889
190	Idaho Power Company	AVA	IPCO	NF	MONTANA OATT	AVAT.NWMT	TNDY		141	141		764		764
191	Idaho Power Company	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	MLCK		264	264		1,430		1,430
192	Idaho Power Company	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		1,224	1,224		6,630		6,630
193	Idaho Power Company	NWMT	IPCO	NF	MONTANA OATT	MLCK	TNDY		93	93		504		504
194	Idaho Power Company	PACE	NWMT	NF	MONTANA OATT	JEFF	MLCK		1,208	1,208		5,764		5,764
195	Idaho Power Company	PPW	IPCO	NF	MONTANA OATT	JEFF	TNDY		48	48		260		260
196	Macquarie Energy, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		400	400		2,168		2,168
197	Macquarie Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY		1,200	1,200		6,500		6,500
198	Macquarie Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		243	243		1,317		1,317
199	Macquarie Energy, LLC	BPAT	AVA	SFP	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		33,600	33,600		168,050		168,050
200	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	BGI	AVAT.NWMT		256	256		1,388		1,388
201	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	CANYONFERRY	AVAT.NWMT		248	248		1,344		1,344
202	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	HOLTER	AVAT.NWMT		655	655		3,550		3,550
203	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	JUDITHGAP	AVAT.NWMT		216	216		999		999
204	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	TFALLS	AVAT.NWMT		338	338		1,832		1,832
205	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	BGI	AVAT.NWMT		1,200	1,200		6,500		6,500
206	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	CANYONFERRY	AVAT.NWMT		552	552		2,990		2,990
207	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	HOLTER	AVAT.NWMT		1,536	1,536		8,320		8,320
208	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	STILLWIND	AVAT.NWMT		864	864		4,680		4,680
209	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	TFALLS	AVAT.NWMT		600	600		3,250		3,250
210	Macquarie Energy, LLC	NWMT	BPA	NF	MONTANA OATT	BGI	BPAT.NWMT		456	456		2,470		2,470
211	Macquarie Energy, LLC	NWMT	BPA	SFP	MONTANA OATT	BGI	BPAT.NWMT		96	96		520		520
212	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	CANYONFERRY	BPAT.NWMT		456	456		2,470		2,470
213	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	HOLTER	BPAT.NWMT		6,168	6,168		33,416		33,416
214	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	SOUTHPEAK	BPAT.NWMT		720	720		3,330		3,330
215	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	STILLWIND	BPAT.NWMT		720	720		3,901		3,901
216	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	TFALLS	BPAT.NWMT		62	62		336		336
217	Macquarie Energy, LLC	NWMT	BPAT	SFP	MONTANA OATT	CANYONFERRY	BPAT.NWMT		744	744		4,030		4,030
218	Macquarie Energy, LLC	NWMT	NWMT	SFP	MONTANA OATT	TFALLS	NWMT.SYSTEM		600	600		3,250		3,250
219	Macquarie Energy, LLC	PPW	AVA	SFP	MONTANA OATT	BRDY	AVAT.NWMT		30,909	30,909		164,110		164,110
220	Macquarie Energy, LLC	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		138,986	138,986		652,034		652,034
221	Macquarie Energy, LLC	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		56	56		304		304
222	Macquarie Energy, LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		191	191		884		884
223	Macquarie Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	BRDY	BPAT.NWMT		792	792		3,815		3,815
224	Macquarie Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		18,625	18,625		84,025		84,025
225	Macquarie Energy, LLC	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM		5,880	5,880		27,160		27,160
226	Macquarie Energy, LLC	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		36,000	36,000		168,050		168,050
227	Macquarie Energy, LLC	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		1	1		5		5
228	Macquarie Energy, LLC	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		105	105		486		486
229	Macquarie Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		247	247		1,223		1,223
230	MAG Energy Solutions	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		2,866	2,866		15,363		15,363
231	MAG Energy Solutions	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		2	2		9		9
232	MAG Energy Solutions	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		1	1		5		5
233	MAG Energy Solutions	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		125	125		678		678
234	MAG Energy Solutions	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		497	497		2,694		2,694
235	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY		42,937	42,937		198,122		198,122
236	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF		3,192	3,192		14,779		14,779
237	MAG Energy Solutions	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	BRDY		7,551	7,551		34,607		34,607
238	MAG Energy Solutions	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	JEFF		1,089	1,089		4,989		4,989
239	MAG Energy Solutions	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT		468	468		2,390		2,390
240	MAG Energy Solutions	PACE	NWMT	NF	MONTANA OATT	JEFF	MATL.NWMT		26	26		141		141
241	MAG Energy Solutions	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT		1	1		5		5
242	MAG Energy Solutions	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		5	5		27		27
243	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		3,730	3,730		17,253		17,253
244	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		140	140		648		648
245	Mercuria Energy America, LLC	GWA	PPW	NF	MONTANA OATT	GLWND1	BRDY		74	74		343		343
246	Mercuria Energy America, LLC	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		52,803	52,803		283,320		283,320
247	Mercuria Energy America, LLC	PPW	PPW	NF	MONTANA OATT	BRDY	YTP		20	20		108		108
248	Mercuria Energy America, LLC	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER		52	52		282		282
249	Mercuria Energy America, LLC	PPW	WAPA	NF	MONTANA OATT	BRDY	GREATFALLS		225	225		1,062		1,062
250	Mercuria Energy America, LLC	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		3,978	3,978		21,561		21,561
251	Mercuria Energy America, LLC	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT		11,156	11,156		51,646		51,646
252	Mercuria Energy America, LLC	WAPA	GWA	NF	MONTANA OATT	GREATFALLS	GLWND1		74	74		343		343
253	Mercuria Energy America, LLC	WAPA	NWMT	SFP	MONTANA OATT	CROSSOVER	NWMT.SYSTEM		8,790	8,790		47,220		47,220
254	Mercuria Energy America, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		30	30		139		139
255	Mercuria Energy America, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		795	795		3,681		3,681
256	Mercuria Energy America, LLC	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY		10,943	10,943		50,654		50,654
257	Mercuria Energy America, LLC	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	JEFF		73	73		338		338
258	Mercuria Energy America, LLC	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	YTP		183	183		847		847
259	Mercuria Energy America, LLC	WAPA	WAPA	NF	MONTANA OATT	CROSSOVER	GREATFALLS		75	75		347		347
260	Morgan Stanley Capital Group, Inc.	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		70	70		326		326
261	Morgan Stanley Capital Group, Inc.	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT		175	175		810		810
262	Morgan Stanley Capital Group, Inc.	AVA	GWA	NF	MONTANA OATT	AVAT.NWMT	GLWND1		239	239		1,145		1,145
263	Morgan Stanley Capital Group, Inc.	AVA	GWA	NF	MONTANA OATT	AVAT.NWMT	GLWND2		202	202		1,018		1,018
264	Morgan Stanley Capital Group, Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT		30,658	30,658		160,957		160,957
265	Morgan Stanley Capital Group, Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM		56	56		304		304
266	Morgan Stanley Capital Group, Inc.	AVA	NWMT	SFP	MONTANA OATT	AVAT.NWMT	MATL.NWMT		9,339	9,339		42,783		42,783
267	Morgan Stanley Capital Group, Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	JEFF		9	9		49		49
268	Morgan Stanley Capital Group, Inc.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		322	322		1,491		1,491
269	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND1		3,708	3,708		18,412		18,412
270	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND2		3,656	3,656		18,807		18,807
271	Morgan Stanley Capital Group, Inc.	BPAT	GWA	SFP	MONTANA OATT	BPAT.NWMT	GLWND1		984	984		5,216		5,216
272	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP		50	50		271		271
273	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		173,432	173,432		879,291		879,291
274	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		488	488		2,473		2,473
275	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	MATL.NWMT		122,229	122,229		606,268		606,268
276	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		213	213		986		986
277	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF		1,313	1,313		6,432		6,432
278	Morgan Stanley Capital Group, Inc.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	JEFF		53,736	53,736		281,928		281,928
279	Morgan Stanley Capital Group, Inc.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP		2,400	2,400		11,100		11,100
280	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND1	AVAT.NWMT		29,370	29,370		144,011		144,011
281	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND2	AVAT.NWMT		20,623	20,623		102,538		102,538
282	Morgan Stanley Capital Group, Inc.	GWA	AVA	SFP	MONTANA OATT	GLWND1	AVAT.NWMT		2,016	2,016		9,894		9,894
283	Morgan Stanley Capital Group, Inc.	GWA	AVA	SFP	MONTANA OATT	GLWND2	AVAT.NWMT		480	480		2,600		2,600
284	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND1	BPAT.NWMT		225,031	225,031		1,140,083		1,140,083
285	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND2	BPAT.NWMT		136,425	136,425		691,717		691,717
286	Morgan Stanley Capital Group, Inc.	GWA	BPAT	SFP	MONTANA OATT	GLWND1	BPAT.NWMT		22,359	22,359		105,936		105,936
287	Morgan Stanley Capital Group, Inc.	GWA	BPAT	SFP	MONTANA OATT	GLWND2	BPAT.NWMT		16,234	16,234		76,766		76,766
288	Morgan Stanley Capital Group, Inc.	GWA	GWA	NF	MONTANA OATT	GLWND1	GLWND2		3	3		16		16
289	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND1	MATL.NWMT		10,189	10,189		51,597		51,597
290	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND1	NWMT.SYSTEM		382	382		1,833		1,833
291	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	MATL.NWMT		2,163	2,163		11,432		11,432
292	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	NWMT.SYSTEM		45,356	45,356		232,119		232,119
293	Morgan Stanley Capital Group, Inc.	GWA	NWMT	SFP	MONTANA OATT	GLWND1	MATL.NWMT		360	360		1,950		1,950
294	Morgan Stanley Capital Group, Inc.	GWA	NWMT	SFP	MONTANA OATT	GLWND2	NWMT.SYSTEM		6,342	6,342		29,268		29,268
295	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	BRDY		16,085	16,085		85,265		85,265
296	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	JEFF		4,716	4,716		24,412		24,412
297	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	BRDY		9,199	9,199		48,928		48,928
298	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	JEFF		812	812		4,094		4,094
299	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND1	BRDY		6,384	6,384		34,580		34,580
300	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	HARDIN	AVAT.NWMT		509	509		2,390		2,390
301	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT		2	2		11		11
302	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		81,002	81,002		412,689		412,689
303	Morgan Stanley Capital Group, Inc.	NWMT	AVA	SFP	MONTANA OATT	HARDIN	AVAT.NWMT		5,640	5,640		26,085		26,085
304	Morgan Stanley Capital Group, Inc.	NWMT	AVA	SFP	MONTANA OATT	MATL.NWMT	AVAT.NWMT		4,659	4,659		22,466		22,466
305	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		802	802		4,189		4,189
306	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	HARDIN	BPAT.NWMT		6,375	6,375		30,178		30,178
307	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	JUDITHGAP	BPAT.NWMT		50	50		232		232
308	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT		168	168		911		911
309	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	374,980	374,980		1,882,301		1,882,301
310	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT	0	5	5		27		27
311	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	1,320	1,320		6,105		6,105
312	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	HARDIN	BPAT.NWMT	0	4,752	4,752		21,978		21,978
313	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	102,025	102,025		528,075		528,075
314	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	COLSTRIP	GLWND1	0	9	9		49		49
315	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	COLSTRIP	GLWND2	0	40	40		217		217
316	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	HARDIN	GLWND1	0	160	160		832		832
317	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	HARDIN	GLWND2	0	9	9		46		46
318	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND1	0	2,142	2,142		10,647		10,647
319	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND2	0	866	866		4,411		4,411
320	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	50,420	50,420		259,615		259,615
321	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	HARDIN	MATL.NWMT	0	47,356	47,356		236,869		236,869
322	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	HARDIN	NWMT.SYSTEM	0	64	64		347		347
323	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	JUDITHGAP	MATL.NWMT	0	40	40		217		217
324	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	KERR	MATL.NWMT	0	99	99		537		537
325	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM	0	244	244		1,322		1,322
326	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	NWMTIMBALANC	MATL.NWMT	0	166	166		825		825
327	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	COLSTRIP	MATL.NWMT	0	30,865	30,865		158,852		158,852
328	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	COLSTRIP	NWMT.SYSTEM	0	6,768	6,768		36,660		36,660
329	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	CROOKEDFALLS	MATL.NWMT	0	744	744		3,441		3,441
330	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	HARDIN	MATL.NWMT	0	14,778	14,778		71,993		71,993
331	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	HARDIN	NWMT.SYSTEM	0	240	240		1,300		1,300
332	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	HARDIN	JEFF	0	50	50		232		232
333	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	10,625	10,625		52,879		52,879
334	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	8,367	8,367		42,898		42,898
335	Morgan Stanley Capital Group, Inc.	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	BRDY	0	1,128	1,128		5,217		5,217
336	Morgan Stanley Capital Group, Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	400	400		1,852		1,852
337	Morgan Stanley Capital Group, Inc.	NWMT	PPW	NF	MONTANA OATT	HARDIN	BRDY	0	21	21		113		113
338	Morgan Stanley Capital Group, Inc.	NWMT	WAUW	NF	MONTANA OATT	HARDIN	CROSSOVER	0	74	74		401		401
339	Morgan Stanley Capital Group, Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	23	23		125		125
340	Morgan Stanley Capital Group, Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	9,521	9,521		51,414		51,414
341	Morgan Stanley Capital Group, Inc.	PACE	NWMT	NF	MONTANA OATT	JEFF	MATL.NWMT	0	20	20		93		93
342	Morgan Stanley Capital Group, Inc.	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT	0	28	28		130		130
343	Morgan Stanley Capital Group, Inc.	PACE	NWMT	SFP	MONTANA OATT	BRDY	MATL.NWMT	0	75,264	75,264		346,159		346,159
344	Morgan Stanley Capital Group, Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	150	150		695		695
345	Morgan Stanley Capital Group, Inc.	PPW	BPAT	SFP	MONTANA OATT	BRDY	BPAT.NWMT	0	21,600	21,600		116,800		116,800
346	Morgan Stanley Capital Group, Inc.	PPW	GWA	NF	MONTANA OATT	BRDY	GLWND1	0	16	16		87		87
347	Morgan Stanley Capital Group, Inc.	WAPA	AVA	NF	MONTANA OATT	GREATFALLS	AVAT.NWMT	0	7,292	7,292		38,172		38,172
348	Morgan Stanley Capital Group, Inc.	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT	0	13,151	13,151		67,023		67,023
349	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY	0	788	788		3,893		3,893
350	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	JEFF	0	555	555		2,570		2,570
351	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT	0	1,440	1,440		6,660		6,660
352	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	NF	MONTANA OATT	GREATFALLS	MATL.NWMT	0	10,367	10,367		52,356		52,356
353	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	SFP	MONTANA OATT	CROSSOVER	MATL.NWMT	0	20,905	20,905		96,450		96,450
354	Naturener Power Watch, LLC	GWA	GWA	SFP	MONTANA OATT	GLWND1	GLWND2	0	43,800	43,800		221,750		221,750
355	Naturener Power Watch, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	JEFF	0	18	18		98		98
356	PacifiCorp	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	3,500	3,500		16,205		16,205
357	PacifiCorp	NWMT	PACE	NF	MONTANA OATT	NWMTIMBALANC	BRDY	0	59	59		273		273
358	PacifiCorp	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	1,940	1,940		9,188		9,188
359	PacifiCorp	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT	0	140	140
360	PacifiCorp	PPW	NWMT	NF	MONTANA OATT	MLCK	JEFF	0	16,417	16,417		88,850		88,850
361	PacifiCorp	PPW	NWMT	SFP	MONTANA OATT	MLCK	JEFF	0	9,216	9,216		49,920		49,920
362	Phillips 66 Energy Trading, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	400	400		2,168		2,168
363	Phillips 66 Energy Trading, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	GTFALLSNWMT	0	55	55		298		298
364	Phillips 66 Energy Trading, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	120	120		650		650
365	Phillips 66 Energy Trading, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	39	39		211		211
366	Phillips 66 Energy Trading, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT	0	80	80		434		434
367	Phillips 66 Energy Trading, LLC	NWMT	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	600	600		3,250		3,250
368	Portland General Electric Company	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	11,478	11,478		55,039		55,039
369	Portland General Electric Company	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	334	334		1,692		1,692
370	Portland General Electric Company	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	785	785		3,824		3,824
371	Portland General Electric Company	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	2,865	2,865		14,141		14,141
372	Portland General Electric Company	NWMT	BPAT	LFP	MONTANA OATT	CLEARWATER	BPAT.NWMT	25	222,900	222,900	1,180,625			1,180,625
373	Portland General Electric Company	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	18,135	18,135		90,951		90,951
374	Portland General Electric Company	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP	0	24	24		114		114
375	Portland General Electric Company	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	1,100	1,100		5,962		5,962
376	Portland General Electric Company	NWMT	NWMT	SFP	MONTANA OATT	COLSTRIP	MATL.NWMT	0	360	360		1,950		1,950
377	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	454	454		2,221		2,221
378	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	1,747	1,747		8,110		8,110
379	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	1,090	1,090		5,047		5,047
380	Portland General Electric Company	PGE	PPW	NF	MONTANA OATT	COLSTRIP	MLCK	0	247	247		1,144		1,144
381	Portland General Electric Company	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	2,000	2,000		9,438		9,438
382	Powerex Corporation	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	65	65		352		352
383	Powerex Corporation	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY	0	294	294		1,593		1,593
384	Powerex Corporation	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	JEFF	0	27	27		146		146
385	Powerex Corporation	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP	0	5,951	5,951		31,591		31,591
386	Powerex Corporation	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER	0	287	287		1,329		1,329
387	Powerex Corporation	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	58	58		314		314
388	Powerex Corporation	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	28,149	28,149		151,793		151,793
389	Powerex Corporation	BPAT	PPW	LFP	MONTANA OATT	BPAT.NWMT	BRDY	76	665,760	665,760	3,370,695			3,370,695
390	Powerex Corporation	BPAT	PPW	LFP	MONTANA OATT	BPAT.NWMT	JEFF	71	621,960	621,960	3,148,939			3,148,939
391	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	435	435		2,308		2,308
392	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF	0	1	1		5		5
393	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	17,204	17,204		84,609		84,609
394	Powerex Corporation	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	566	566		2,664		2,664
395	Powerex Corporation	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	691	691		3,745		3,745
396	Powerex Corporation	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	842	842		3,898		3,898
397	Powerex Corporation	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	3	3		14		14
398	Powerex Corporation	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	6	6		33		33
399	Powerex Corporation	PACE	NWMT	NF	MONTANA OATT	YTP	COLSTRIP	0	1,361	1,361		6,301		6,301
400	Powerex Corporation	PPW	AVA	LFP	MONTANA OATT	YTP	AVAT.NWMT	0	1,440	1,440		7,870		7,870
401	Powerex Corporation	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT	0	12	12		65		65
402	Powerex Corporation	PPW	AVA	NF	MONTANA OATT	JEFF	AVAT.NWMT	0	24	24		130		130
403	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	441	441		2,225		2,225
404	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	JEFF	BPAT.NWMT	0	16	16		87		87
405	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	6,553	6,553		31,009		31,009
406	Powerex Corporation	PPW	PPW	NF	MONTANA OATT	YTP	BRDY	0	10	10		46		46
407	Powerex Corporation	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	316	316		1,713		1,713
408	Powerex Corporation	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	58,884	58,884		274,533		274,533
409	Powerex Corporation	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	7,750	7,750		37,273		37,273
410	Powerex Corporation	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP	0	624	624		2,886		2,886
411	Powerex Corporation	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	COLSTRIP	0	1,806	1,806		8,360		8,360
412	Public Service Company of Colorado	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	250	250		1,158		1,158
413	Puget Sound Energy Marketing	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	34,133	34,133		171,355		171,355
414	Puget Sound Energy Marketing	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	91,872	91,872		454,339		454,339
415	Puget Sound Energy Marketing	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT	0	25	25		116		116
416	Puget Sound Energy Marketing	AVA	MLCK	NF	MONTANA OATT	COLSTRIP	MLCK	0	241	241		1,305		1,305
417	Puget Sound Energy Marketing	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	388	388		1,970		1,970
418	Puget Sound Energy Marketing	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	151	151		818		818
419	Puget Sound Energy Marketing	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	39,333	39,333		209,319		209,319
420	Puget Sound Energy Marketing	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	139,410	139,410		686,460		686,460
421	Puget Sound Energy Marketing	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	384	384		2,081		2,081
422	Puget Sound Energy Marketing	PPW	PPW	NF	MONTANA OATT	MLCK	BRDY	0	1	1		5		5
423	Rainbow Electric Marketing Corp.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	17	17		92		92
424	Rainbow Electric Marketing Corp.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	611	611		2,893		2,893
425	Rainbow Electric Marketing Corp.	BPAT	BPAT	NF	MONTANA OATT	BPAT.NWMT	BPAT.NWMT	0	53	53		287		287
426	Rainbow Electric Marketing Corp.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	4,795	4,795		25,989		25,989
427	Rainbow Electric Marketing Corp.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	5	5		27		27
428	Rainbow Electric Marketing Corp.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	60	60		278		278
429	Rainbow Electric Marketing Corp.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	150	150		695		695
430	Rainbow Electric Marketing Corp.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	10,209	10,209		55,003		55,003
431	Rainbow Electric Marketing Corp.	NWMT	AVA	NF	MONTANA OATT	CANYONFERRY	AVAT.NWMT	0	78	78		361		361
432	Rainbow Electric Marketing Corp.	NWMT	AVA	NF	MONTANA OATT	CLEARWATER	AVAT.NWMT	0	72	72		333		333
433	Rainbow Electric Marketing Corp.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	657	657		3,561		3,561
434	Rainbow Electric Marketing Corp.	NWMT	BPAT	NF	MONTANA OATT	CANYONFERRY	BPAT.NWMT	0	55	55		255		255
435	Rainbow Electric Marketing Corp.	NWMT	BPAT	NF	MONTANA OATT	CLEARWATER	BPAT.NWMT	0	150	150		695		695
436	Rainbow Electric Marketing Corp.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	100	100		542		542
437	Rainbow Electric Marketing Corp.	NWMT	PACE	NF	MONTANA OATT	CLEARWATER	BRDY	0	2,349	2,349		10,876		10,876
438	Rainbow Electric Marketing Corp.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	4,225	4,225		22,900		22,900
439	Rainbow Electric Marketing Corp.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	147	147		797		797
440	Rainbow Electric Marketing Corp.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	655	655		3,550		3,550
441	Rainbow Electric Marketing Corp.	PACE	NWMT	NF	MONTANA OATT	JEFF	MATL.NWMT	0	628	628		3,404		3,404
442	Rainbow Electric Marketing Corp.	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT	0	171	171		927		927
443	Rainbow Electric Marketing Corp.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	15,047	15,047		70,052		70,052
444	Rainbow Electric Marketing Corp.	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT	0	5,040	5,040		27,240		27,240
445	Rainbow Electric Marketing Corp.	PPW	PPW	NF	MONTANA OATT	YTP	JEFF	0	30	30		139		139
446	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER	0	29	29		134		134
447	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	35,108	35,108		184,622		184,622
448	Rainbow Electric Marketing Corp.	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER	0	2,592	2,592		14,040		14,040
449	Rainbow Electric Marketing Corp.	WAPA	AVA	NF	MONTANA OATT	GREATFALLS	AVAT.NWMT	0	563	563		2,607		2,607
450	Rainbow Electric Marketing Corp.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	6,012	6,012		29,031		29,031
451	Rainbow Electric Marketing Corp.	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT	0	1,440	1,440		6,705		6,705
452	Rainbow Electric Marketing Corp.	WAPA	NWMT	NF	MONTANA OATT	CROSSOVER	NWMT.SYSTEM	0	4	4		22		22
453	Rainbow Electric Marketing Corp.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY	0	180	180		833		833
454	Rainbow Electric Marketing Corp.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	25,425	25,425		120,549		120,549
455	Rainbow Electric Marketing Corp.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY	0	734	734		3,398		3,398
456	Rainbow Electric Marketing Corp.	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP	0	8,496	8,496		45,469		45,469
457	Rainbow Electric Marketing Corp.	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT	0	78	78		423		423
458	Shell Energy North America	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	6	6		28		28
459	Shell Energy North America	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	400	400		1,852		1,852
460	Shell Energy North America	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	183	183		873		873
461	Shell Energy North America	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	1,235	1,235		6,687		6,687
462	Shell Energy North America	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	58	58		269		269
463	Shell Energy North America	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	20	20		93		93
464	Shell Energy North America	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	2,396	2,396		11,278		11,278
465	Shell Energy North America	BPAT	WAPA	SFP	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	3,600	3,600		16,650		16,650
466	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	CLEARWATER	BPAT.NWMT	0	829	829		3,838		3,838
467	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	341	341		1,848		1,848
468	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	452	452		2,251		2,251
469	Shell Energy North America	NWMT	NWMT	NF	MONTANA OATT	BGI	GTFALLSNWMT	0	24	24		111		111
470	Shell Energy North America	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM	0	29	29		144		144
471	Shell Energy North America	NWMT	NWMT	NF	MONTANA OATT	SOUTHPEAK	GTFALLSNWMT	0	13	13		60		60
472	Shell Energy North America	NWMT	WAUW	NF	MONTANA OATT	BGI	GREATFALLS	0	24	24		111		111
473	Shell Energy North America	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	73	73		357		357
474	Shell Energy North America	PPW	BPAT	SFP	MONTANA OATT	BRDY	BPAT.NWMT	0	110,400	110,400		590,250		590,250
475	Shell Energy North America	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM	0	1,968	1,968		9,102		9,102
476	Shell Energy North America	PPW	NWMT	SFP	MONTANA OATT	BRDY	NWMT.SYSTEM	0	432	432		1,998		1,998
477	Shell Energy North America	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER	0	520	520		2,818		2,818
478	Shell Energy North America	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	69	69		319		319
479	Shell Energy North America	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	200	200		1,084		1,084
480	SociVolta, Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	1	1		5		5
481	TEC Energy Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	72	72		390		390
482	TEC Energy Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	75	75		407		407
483	TEC Energy Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	10	10		54		54
484	TEC Energy Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	162	162		878		878
485	TEC Energy Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	695	695		3,767		3,767
486	TEC Energy Inc.	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT	0	20	20		108		108
487	The Energy Authority	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY	0	48	48		260		260
488	The Energy Authority	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	494	494		2,519		2,519
489	The Energy Authority	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	267	267		1,447		1,447
490	The Energy Authority	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	69	69		374		374
491	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	1,190	1,190		5,830		5,830
492	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF	0	230	230		1,183		1,183
493	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	700	700		3,241		3,241
494	The Energy Authority	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	BRDY	0	480	480		2,220		2,220
495	The Energy Authority	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	1,499	1,499		7,806		7,806
496	The Energy Authority	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	878	878		4,759		4,759
497	The Energy Authority	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	4,913	4,913		26,609		26,609
498	The Energy Authority	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	870	870		4,715		4,715
499	The Energy Authority	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	75	75		407		407
500	The Energy Authority	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	90	90		488		488
501	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	3,669	3,669		17,388		17,388
502	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	901	901		4,251		4,251
503	The Energy Authority	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM	0	1	1		5		5
504	The Energy Authority	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	1,312	1,312		6,835		6,835
505	The Energy Authority	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER	0	1,152	1,152		6,240		6,240
506	The Energy Authority	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT	0	1	1		5		5
507	The Energy Authority	WAPA	AVA	SFP	MONTANA OATT	CROSSOVER	AVAT.NWMT	0	2,928	2,928		15,740		15,740
508	The Energy Authority	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	61,877	61,877		296,972		296,972
509	The Energy Authority	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	70,421	70,421		335,334		335,334
510	The Energy Authority	WAPA	NWMT	NF	MONTANA OATT	CROSSOVER	NWMT.SYSTEM	0	425	425		1,968		1,968
511	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY	0	50	50		232		232
512	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF	0	54	54		293		293
513	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	5,137	5,137		24,239		24,239
514	Transalta Energy Marketing (US) Inc.	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER	0	284	284		1,452		1,452
515	Transalta Energy Marketing (US) Inc.	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	6	6		33		33
516	Transalta Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	1,260	1,260		6,829		6,829
517	Transalta Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	171	171		902		902
518	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	627	627		3,232		3,232
519	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF	0	65	65		352		352
520	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	1,264	1,264		6,322		6,322
521	Transalta Energy Marketing (US) Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	4,176	4,176		21,483		21,483
522	Transalta Energy Marketing (US) Inc.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	1,105	1,105		5,705		5,705
523	Transalta Energy Marketing (US) Inc.	NWMT	AVA	NF	MONTANA OATT	NWMTIMBALANC	AVAT.NWMT	0	20	20		93		93
524	Transalta Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	13,840	13,840		67,599		67,599
525	Transalta Energy Marketing (US) Inc.	NWMT	BPAT	SFP	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	1,872	1,872		8,658		8,658
526	Transalta Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	236	236		1,093		1,093
527	Transalta Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	150	150		695		695
528	Transalta Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	101	101		547		547
529	Transalta Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	828	828		4,448		4,448
530	Transalta Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	JEFF	BPAT.NWMT	0	8,691	8,691		47,081		47,081
531	Transalta Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	4,181	4,181		19,344		19,344
532	Transalta Energy Marketing (US) Inc.	PPW	BPAT	SFP	MONTANA OATT	JEFF	BPAT.NWMT	0	2,736	2,736		14,820		14,820
533	Transalta Energy Marketing (US) Inc.	PPW	PPW	NF	MONTANA OATT	YTP	ANTE	0	24	24		111		111
534	Transalta Energy Marketing (US) Inc.	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER	0	384	384		2,081		2,081
535	Transalta Energy Marketing (US) Inc.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	118	118		546		546
536	Transalta Energy Marketing (US) Inc.	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT	0	45	45		208		208
537	Transalta Energy Marketing (US) Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	8,259	8,259		39,199		39,199
538	Transalta Energy Marketing (US) Inc.	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	816	816		3,774		3,774
539	Transalta Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY	0	50	50		232		232
540	Transalta Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	7,149	7,149		33,953		33,953
541	Transalta Energy Marketing (US) Inc.	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP	0	5,355	5,355		24,975		24,975
542	Vitol Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	1,256	1,256		6,808		6,808
543	Vitol Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	1,060	1,060		5,742		5,742
544	Vitol Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	1,165	1,165		6,314		6,314
545	Vitol Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	200	200		1,084		1,084
546	Western Area Power Administration	NWMT	NWMT	NF	MONTANA OATT	CANYONFERRY	NWMT.SYSTEM	0	8,832	8,832		46,072		46,072
547	Western Area Power Administration	NWMT	NWMT	SFP	MONTANA OATT	CANYONFERRY	NWMT.SYSTEM	0	2,930	2,930		15,740		15,740
548	Western Area Power Administration	NWMT	WAPA	NF	MONTANA OATT	CANYONFERRY	CROSSOVER	0	130,887	130,887		616,576		616,576
549	Western Area Power Administration	NWMT	WAPA	SFP	MONTANA OATT	CANYONFERRY	CROSSOVER	0	151,239	151,239		816,255		816,255
550	Western Area Power Administration	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	158,293	158,293		845,122		845,122
551	Western Area Power Administration	PPW	WAPA	NF	MONTANA OATT	YTP	GREATFALLS	0	3,589	3,589		16,617		16,617
552	Western Area Power Administration	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER	0	121,084	121,084		656,240		656,240
553	Western Area Power Administration	PPW	WAPA	SFP	MONTANA OATT	YTP	GREATFALLS	0	7,200	7,200		33,610		33,610
554	Western Area Power Administration	WAPA	NWMT	NF	MONTANA OATT	GREATFALLS	NWMT.SYSTEM	0	10,170	10,170		49,267		49,267
555	Western Area Power Administration	WAPA	NWMT	SFP	MONTANA OATT	GREATFALLS	NWMT.SYSTEM	0	744	744		3,935		3,935
556	Western Area Power Administration	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	10,677	10,677		49,781		49,781
557	Western Area Power Administration	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	YTP	0	7,200	7,200		33,610		33,610
558	Western Area Power Administration	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP	0	224,754	224,754		1,148,337		1,148,337
559	Western Area Power Administration	WAPA	WAPA	NF	MONTANA OATT	CROSSOVER	GREATFALLS	0	29,520	29,520		145,920		145,920
560	Western Area Power Administration	WAPA	WAPA	NF	MONTANA OATT	GREATFALLS	CROSSOVER	0	146,804	146,804		752,382		752,382
561	Western Area Power Administration	WAPA	WAPA	SFP	MONTANA OATT	CROSSOVER	GREATFALLS	0	21,370	21,370		100,830		100,830
562	Western Area Power Administration	WAPA	WAPA	SFP	MONTANA OATT	GREATFALLS	CROSSOVER	0	35,510	35,510		168,050		168,050
563	Western Area Power Administration	WAUW	NWMT	SFP	MONTANA OATT	GREATFALLS	GTFALLSNWMT	0	8,760	8,760		46,925		46,925
564	SOUTH DAKOTA
565	BRYANT, CITY OF	WAPA	BRYANT	LFP	VOL 2	HURON 115 KV BUS	BRYANT 25 KV		4,054	4,054	33,141			33,141
566	GROTON, CITY OF	WAPA	GROTON	LFP	VOL 2	HURON 115 KV BUS	GROTON 69 KV		17,364	17,364	1,141			1,141
567	LANGFORD, CITY OF	WAPA	LANGFORD	LFP	VOL 2	HURON 115 KV BUS	LANGFORD 12.5 KV		3,121	3,121	23,542			23,542
568	Southwest Power Pool (SPP)	SPP	Various	LFP	SCH 7	Various	Various						226,510	(a) 226,510
569	Southwest Power Pool (SPP)	SPP	Various	NF	SCH 8	Various	Various						88,544	(b) 88,544
570	Southwest Power Pool (SPP)	SPP	Various	FNS	SCH 9	Various	Various						6,207,809	(c) 6,207,809
571	Southwest Power Pool (SPP)	SPP	Various	LFP	SCH 11	Various	Various						153,933	(d) 153,933
572	Rounding								2	2	3		1	4
573	TOTAL							1,276	13,627,348	13,627,348	42,906,942	29,417,961	6,676,797	79,001,700
35	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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	25,983	25,983	51,760			51,760
3	Bonneville Power Admin	OLF					(a) 3,538,536	3,538,536
4	Southwest Power Pool (MT)	FNS	106,137	106,137	1,746,644			1,746,644
5	Glacier Electric Coop	OLF	1	1	1,589			1,589
6	Sun River Elect Coop	OLF	3,708	3,708	21,210			21,210
7	Supply:
8	Avista	NF	2,347	2,347		28,302		28,302
9	Bonneville Power Admin	NF	440,617	440,617		1,284,683		1,284,683
10	Seattle City Light	NF	7,849	7,849		13,213		13,213
11	SOUTH DAKOTA:
12	East River	FNS			389			389
13	West Central Elect COOP	FNS			8,935			8,935
14	OtterTail Power (for MISO)	FNS			8,985			8,985
15	Southwest Power Pool	FNS			19,280,494			19,280,494
16	Rounding				1	1	1	3
	TOTAL		586,642	586,642	21,120,007	1,326,199	3,538,537	25,984,743

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:

12/31/2023

Year/Period of Report

End of:

2023

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	625,612
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	96,896
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	10,425,797
7	Board of Directors	2,062,359
8	Amortization of upfront fees	432,286
9	Our Portion of Shared Generation	1,626,479
10	Human Resources general expenses (non-labor and not provided for elsewhere)	22,793
11	Miscellaneous	29,680
46	MiscellaneousGeneralExpenses TOTAL	(a) 15,262,542

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: MiscellaneousGeneralExpenses


	Montana Operations	South Dakota Operations	Total 930.2
Universal System Benefits Charge	10,425,797	—	10,425,797
Our Portion of Shared Ownership Gen	1,626,479	—	1,626,479
	12,052,276	—	12,052,276

Board of Directors Fees	1,775,857	286,502	2,062,359
Shareholder Expense	83,438	13,458	96,896
Industry & Association Dues	389,621	235,991	625,612
Amortization of upfront fees	372,197	60,089	432,286
Human Resources general expenses (non-labor and not provided for elsewhere)	17,016	5,777	22,793
Miscellaneous	(28,910)	(770)	(29,680)
	2,609,219	601,047	3,210,266

Total Account 930.2	14,661,495	601,047	15,262,542

Montana Operations Miscellaneous General Expenses account 930.2 includes $126,180 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:

12/31/2023

Year/Period of Report

End of:

2023

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			2,024,953		2,024,953
2	Steam Production Plant	7,822,272				7,822,272
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional	10,972,565				10,972,565
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	19,784,243		3,537		19,787,780
7	Transmission Plant	29,714,082		501,114		30,215,196
8	Distribution Plant	64,527,020		25,630		64,501,390
9	Regional Transmission and Market Operation
10	General Plant	10,813,479				10,813,479
11	Common Plant-Electric	5,675,151		7,115,290		12,790,441
12	TOTAL	(a) 149,308,812		(b) 9,619,264		158,928,076

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. For our Montana operations, 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%. Common amortization expense is allocated to 72% to electric and 28% to gas based on allocation studies. For our South Dakota operations, the rates used to compute amortization charges for 'Intangible Plant - Electric' (Accoutn 404) are as follows: 303 Intangible Plant: Five Year Software 20%; 303 Intangbile Plant: 10 Year Software 10%. Common amortization expense is allocated 85% to electric and 15% to gas based on allocation studies.

	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:

12/31/2023

Year/Period of Report

End of:

2023

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	—	—	2,023,292	—	2,023,292
2	Steam Production Plant	3,943,231	—	—	—	3,943,231
3	Nuclear Production Plant		—	—	—
4	Hydraulic Production Plant‐Conventional	10,972,565	—	—	—	10,972,565
5	Hydraulic Production Plant‐Pumped Storage		—	—	—	—
6	Other Production Plant	11,181,833	—	3,537	—	11,185,370
7	Transmission Plant	22,914,345	—	501,114	—	23,415,459
8	Distribution Plant	53,220,482	—	(25,630)	—	53,194,852
9	General Plant	9,193,022	—		—	9,193,022
10	Common Plant-Electric	3,416,785	—	5,673,236	—	9,090,021
11	TOTAL	114,842,263	—	8,175,549	—	123,017,812

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	—	—	1,661	—	1,661
2	Steam Production Plant	3,879,042	—	—	—	3,879,042
3	Nuclear Production Plant	—	—	—	—
4	Hydraulic Production Plant‐Conventional	—	—	—	—
5	Hydraulic Production Plant‐Pumped Storage	—	—	—	—
6	Other Production Plant	8,602,410	—	—	—	8,602,410
7	Transmission Plant	6,799,737	—	—	—	6,799,737
8	Distribution Plant	11,306,538	—	—	—	11,306,538
9	General Plant	1,620,457	—	—	—	1,620,457
10	Common Plant-Electric	2,258,365	—	1,442,054	—	3,700,419
11	TOTAL	34,466,549	—	1,443,715	—	35,910,264

(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	$	20,247,607	50	$	331,421	331,421
303	8,186,639		5	1,155,994		1,155,994
303	868,284		30	29,001		29,001
340.2	89,998		25, 30	3,537		3,537
350.2	33,186,375		58	501,114		501,114
360.2	4,346,460		60	(25,630)		(25,630)
4303	60,836,356		5, 10	8,856,402		6,503,608

	127,761,719			10,851,839		8,499,045

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:

12/31/2023

Year/Period of Report

End of:

2023

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 (b) + (c) (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	1,536,870		1,536,870		Electric	928	1,536,870
4	South Dakota PUC Electric Rate Filings		43,774	43,774		Electric	928	43,774	43,774			43,774
5	Montana PSC Electric & Gas Rate Filings		393,420	393,420		Electric	928	393,420
6	Montana PSC Electric & Gas Rate Filings		190,235	190,235		Gas	928	190,235
7	FERC Administrative Charges Allocated to
8	Generating Stations Under Project License	1,799,751		1,799,751		Electric	928	1,799,751
46	TOTAL	3,336,621	539,881	(a) 3,876,502				3,876,502	43,774			43,774

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: RegulatoryCommissionExpensesAmount

Montana electric regulatory commission expenses totaled $3,727,822 for 2023. This includes $1,538,707 in expenses that are transmission specific.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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:

12/31/2023

Year/Period of Report

End of:

2023

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	9,009,394
4	SalariesAndWagesElectricOperationTransmission Transmission	7,716,306
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	12,758,052
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	4,893,271
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	3,809,773
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	30,945,198
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	69,131,994
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	2,193,213
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	2,146,830
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	9,457,513
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	3,107,861
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	16,905,417
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	11,202,607
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	9,863,136
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	22,215,565
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	4,893,271
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	3,809,773
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	34,053,059
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	86,037,411		86,037,411
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)	1,565,255
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply	64,677
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing	639,250
35	SalariesAndWagesGasOperationTransmission Transmission	4,096,410
36	SalariesAndWagesGasOperationDistribution Distribution	8,996,605
37	SalariesAndWagesGasCustomerAccounts Customer Accounts	1,981,297
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational	1,596,008
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General	12,078,295
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)	31,017,797
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)	157,121
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing	149,036
47	SalariesAndWagesGasMaintenanceTransmission Transmission	918,382
48	SalariesAndWagesGasMaintenanceDistribution Distribution	3,179,352
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General	1,254,132
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)	5,658,023
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,	1,722,376
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)	64,677
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru	788,286
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)	5,014,792
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)	12,175,957
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)	1,981,297
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)	1,596,008
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)	13,332,427
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)	36,675,820		36,675,820
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance	32,282		32,282
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	122,745,513		122,745,513
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	28,928,124		28,928,124
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant	10,899,865		10,899,865
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):	37,419		37,419
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	39,865,408		39,865,408
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)	928,160		928,160
80	SalariesAndWagesOtherAccountsDescription Expenses of Non-Utility Operations (Account 417)	964,411		964,411
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	1,892,571		1,892,571
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	164,503,492		(a)(b) 164,503,492

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) 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

718,451

TRANSMISSION

415,029


5	REGIONAL MARKET	0
6	DISTRIBUTION	2,188,303
7	CUSTOMER ACCOUNTS	401,462
8	CUSTOMER SERVICE & INFORMATION	1,141,813
9	SALES	0
10	ADMINISTRATIVE & GENERAL	3,804,947
11	TOTAL OPERATION	8,670,005
12	MAINTENANCE
13	PRODUCTION	303,851
14	TRANSMISSION	251,630
15	REGIONAL MARKET	0
16	DISTRIBUTION	1,594,937
17	ADMINISTRATIVE & GENERAL	182,829
18	TOTAL MAINTENANCE	2,333,247
19	TOTAL OPERATION & MAINTENANCE
20	PRODUCTION	1,022,302
21	TRANSMISSION	666,659
22	REGIONAL MARKET	0
23	DISTRIBUTION	3,783,240
24	CUSTOMER ACCOUNTS	401,462
25	CUSTOMER SERVICE & INFORMATION	1,141,813
26	SALES	0
27	ADMINISTRATIVE & GENERAL	3,987,776
28	TOTAL OPERATION & MAINTENANCE	11,003,252	0	11,003,252
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	33,200
36	DISTRIBUTION	3,807,097
37	CUSTOMER ACCOUNTS	449,525
38	CUSTOMER SERVICE & INFORMATION	734,736
39	SALES	0
40	ADMINISTRATIVE & GENERAL	2,954,523
41	TOTAL OPERATION	7,979,081
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	1,914
48	DISTRIBUTION	991,553
49	ADMINISTRATIVE & GENERAL	68,297
50	TOTAL MAINTENANCE	1,061,764
	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	35,114
57	DISTRIBUTION	4,798,650
58	CUSTOMER ACCOUNTS	449,525


59	CUSTOMER SERVICE & INFORMATION	734,736
60	SALES	0
61	ADMINISTRATIVE & GENERAL	3,022,820
62	TOTAL OPERATION & MAINTENANCE	9,040,845	0	9,040,845
63	OTHER UTILITY DEPARTMENTS
64	OPERATION & MAINTENANCE
65	TOTAL ALL UTILITY DEPARTMENTS	20,044,097	0	20,044,097
66	UTILITY PLANT
67	CONSTRUCTION (BY UTILITY DEPARTMENT)
68	ELECTRIC PLANT	5,407,639	0	5,407,639
69	GAS PLANT	1,819,319	0	1,819,319
70	OTHER	0	0	0
71	TOTAL CONSTRUCTION	7,226,958	0	7,226,958
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)	9,576,579		9,576,579
79	A/R MISCELLANEOUS (ACCT 143)	0		0
80	SEVERANCE PAYMENTS (ACCT 182)			0
81	EXPENSES OF NON-UTILITY OP (ACCT 417)	26,152	0
82	OTHER			0
83
98	TOTAL OTHER ACCOUNTS	9,602,731	0	9,602,731
99	TOTAL SALARIES AND WAGES	36,873,786	0	36,873,786

(b) 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	8,290,943
4	TRANSMISSION	7,301,277
5	REGIONAL MARKET	0
6	DISTRIBUTION	10,569,749
7	CUSTOMER ACCOUNTS	4,491,809
8	CUSTOMER SERVICE & INFORMATION	2,667,960
9	SALES	0
10	ADMINISTRATIVE & GENERAL	27,140,251
11	TOTAL OPERATION	60,461,989
12	MAINTENANCE
13	PRODUCTION	1,889,362
14	TRANSMISSION	1,895,200
15	REGIONAL MARKET	0
16	DISTRIBUTION	7,862,576
17	ADMINISTRATIVE & GENERAL	2,925,032
18	TOTAL MAINTENANCE	14,572,170
19	TOTAL OPERATION & MAINTENANCE
20	PRODUCTION	10,180,305
21	TRANSMISSION	9,196,477
22	REGIONAL MARKET	0
23	DISTRIBUTION	18,432,325
24	CUSTOMER ACCOUNTS	4,491,809
25	CUSTOMER SERVICE & INFORMATION	2,667,960
26	SALES	0
27	ADMINISTRATIVE & GENERAL	30,065,283
28	TOTAL OPERATION & MAINTENANCE	75,034,159	0	75,034,159
29	GAS
30	OPERATION
31	PRODUCTION - MANUFACTURED GAS	0
32	PRODUCTION - NAT. GAS	1,565,255
33	OTHER GAS SUPPLY	64,677
34	STORAGE, LNG TERMINAL PROCESSING	639,250
35	TRANSMISSION	4,063,210
36	DISTRIBUTION	5,189,508
37	CUSTOMER ACCOUNTS	1,531,772
38	CUSTOMER SERVICE & INFORMATION	861,272
39	SALES	0
40	ADMINISTRATIVE & GENERAL	9,123,772
41	TOTAL OPERATION	23,038,716
42	MAINTENANCE
43	PRODUCTION - MANUFACTURED GAS	0
44	PRODUCTION - NATURAL GAS	157,121


45	OTHER GAS SUPPLY	0
46	STORAGE, LNG TERMINAL PROCESSING	149,036
47	TRANSMISSION	916,468
48	DISTRIBUTION	2,187,799
49	ADMINISTRATIVE & GENERAL	1,185,835
50	TOTAL MAINTENANCE	4,596,259
	GAS (CONTINUED)
51	TOTAL OPERATION & MAINTENANCE
52	PRODUCTION - MANUFACTURED GAS	0
53	PRODUCTION - NATURAL GAS	1,722,376
54	OTHER GAS SUPPLY	64,677
55	STORAGE, LNG TERMINAL PROCESSING	788,286
56	TRANSMISSION	4,979,678
57	DISTRIBUTION	7,377,307
58	CUSTOMER ACCOUNTS	1,531,772
59	CUSTOMER SERVICE & INFORMATION	861,272
60	SALES	0
61	ADMINISTRATIVE & GENERAL	10,309,607
62	TOTAL OPERATION & MAINTENANCE	27,634,975	0	27,634,975
63	OTHER UTILITY DEPARTMENTS
64	OPERATION & MAINTENANCE	32,282	0	32,282
65	TOTAL ALL UTILITY DEPARTMENTS	102,701,416	0	102,701,416
66	UTILITY PLANT
67	CONSTRUCTION (BY UTILITY DEPARTMENT)
68	ELECTRIC PLANT	23,520,485	0	23,520,485
69	GAS PLANT	9,080,546	0	9,080,546
70	OTHER	37,419	0	37,419
71	TOTAL CONSTRUCTION	32,638,450	0	32,638,450
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)	6,465,182		6,465,182
79	A/R MISCELLANEOUS (ACCT 143)	0		0
80	SEVERANCE PAYMENTS (ACCT 182)			0
81	EXPENSES OF NON-UTILITY OP (ACCT 417)	938,259		938,259
82	OTHER			0
83
98	TOTAL OTHER ACCOUNTS	7,403,441	0	7,403,441
99	TOTAL SALARIES AND WAGES	142,743,307	0	142,743,307

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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, 2023

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	57,054,307	42,831,444	14,222,863

C389	Land & Land Rights	6,114,170	4,436,978	1,677,192

C390	Structures & Improvements	120,932,436	91,361,332	29,571,104

C391	Office Furniture & Equipment	24,084,783	18,525,348	5,559,435

C392	Transportation Equipment	10,528,023	8,170,806	2,357,217

C393	Stores Equipment	35,559	30,225	5,334

C394	Tools/Shop/Garage Equipment	388,199	310,013	78,186

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	2,474,699	2,103,494	371,205

C397	Communication Equipment	41,171,502	24,315,342	16,856,160

C398	Miscellaneous	1,570,396	1,135,554	434,842

	Subtotal	264,354,074	193,220,536	71,133,538


Construction Work in Progress		11,827,171

	Total	276,181,245


NORTHWESTERN ENERGY - MONTANA COMMON UTILITY PLANT

	Item # 1
	Common Utility Plant at December 31, 2023

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	47,205,971	34,460,359	12,745,612

C389	Land & Land Rights	4,897,830	3,403,089	1,494,741

C390	Structures & Improvements	80,273,261	56,801,033	23,472,228

C391	Office Furniture & Equipment	16,017,579	11,668,225	4,349,354

C392	Transportation Equipment	6,483,444	4,732,914	1,750,530

C393	Stores Equipment	0	0	0

C394	Tools/Shop/Garage Equipment	184,907	137,215	47,692

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	0	0	0

C397	Communication Equipment	36,673,560	20,492,091	16,181,469

C398	Miscellaneous	1,542,567	1,111,899	430,668

	Subtotal	193,279,119	132,806,825	60,472,294


Construction Work in Progress		10,595,775


NORTHWESTERN ENERGY - SOUTH DAKOTA COMMON UTILITY PLANT

	Item # 1
	Common Utility Plant at December 31, 2023

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	9,848,335	8,371,085	1,477,250

C389	Land & Land Rights	1,216,340	1,033,889	182,451

C390	Structures & Improvements	40,659,175	34,560,299	6,098,876

C391	Office Furniture & Equipment	8,067,204	6,857,123	1,210,081

C392	Transportation Equipment	4,044,579	3,437,892	606,687

C393	Stores Equipment	35,559	30,225	5,334

C394	Tools/Shop/Garage Equipment	203,292	172,798	30,494

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	2,474,699	2,103,494	371,205

C397	Communication Equipment	4,497,941	3,823,250	674,691

C398	Miscellaneous	27,832	23,657	4,175

	Subtotal	71,074,956	60,413,712	10,661,244


Construction Work in Progress		1,231,395	1,046,686	184,709

	Total	72,306,351


NORTHWESTERN ENERGY - CONSOLIDATED COMMON UTILITY ACCUMULATED DEPRECIATION

	Item # 2
	Common Utility Accumulated Depreciation Reserve At December 31, 2023

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	(20,481,215)	(15,411,929)	(5,069,286)

C389	Land & Land Rights	166,415	117,903	48,512

C390	Structures & Improvements	(21,928,049)	(16,847,668)	(5,080,381)

C391	Office Furniture & Equipment	(4,674,199)	(3,240,270)	(1,433,929)

C392	Transportation Equipment	(3,380,520)	(2,736,180)	(644,340)

C393	Stores Equipment	(8,889)	(7,467)	(1,422)

C394	Tools/Shop/Garage Equipment	(83,672)	(70,269)	(13,403)

C395	Laboratory Equipment	0	0	0

C396	Power Operated Equipment	(1,094,954)	(919,761)	(175,193)

C397	Communication Equipment	(23,593,664)	(13,903,865)	(9,689,799)

C398	Miscellaneous	44,306	44,999	(693)

	Total	(75,034,441)	(52,974,507)	(22,059,934)


NORTHWESTERN ENERGY - MONTANA COMMON UTILITY ACCUMULATED DEPRECIATION

	Item # 2
	Common Utility Accumulated Depreciation Reserve At December 31, 2023

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	16,293,562	11,894,300	4,399,262

C389	Land & Land Rights	(166,415)	(117,903)	(48,512)

C390	Structures & Improvements	10,524,920	7,269,040	3,255,880

C391	Office Furniture & Equipment	6,143,161	4,474,198	1,668,963

C392	Transportation Equipment	940,519	686,579	253,940

C393	Stores Equipment

C394	Tools/Shop/Garage Equipment		112	39

C395	Laboratory Equipment

C396	Power Operated Equipment

C397	Communication Equipment	19,779,257	10,699,763	9,079,494

C398	Miscellaneous	64,850	46,692	18,158

	Total	53,580,005	34,952,781	18,627,224


NORTHWESTERN ENERGY - SOUTH DAKOTA COMMON UTILITY ACCUMULATED DEPRECIATION

	Item # 2
	Common Utility Accumulated Depreciation Reserve At December 31, 2023

PLANT ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	4,187,655	3,517,630	670,025

C389	Land & Land Rights	0	0	0

C390	Structures & Improvements	11,403,129	9,578,628	1,824,501

C391	Office Furniture & Equipment	(1,468,962)	(1,233,928)	(235,034)

C392	Transportation Equipment	2,440,000	2,049,600	390,400

C393	Stores Equipment	8,889	7,467	1,422

C394	Tools/Shop/Garage Equipment	83,520	70,157	13,363

C395	Laboratory Equipment

C396	Power Operated Equipment	1,094,954	919,761	175,193

C397	Communication Equipment	3,814,407	3,204,102	610,305

C398	Miscellaneous	(109,156)	(91,691)	(17,465)

	Total	21,454,436	18,021,726	3,432,710


NORTHWESTERN ENERGY - COMMON UTILITY PLANT EXPENSES FOR THE YEARS ENDING DECEMBER 31, 2023

Item #3

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

Electric:

Depreciation			5,675,151	5,675,151
Amortization			7,115,290	7,115,290
Taxes Other than Income		5,183,712		5,183,712
Administrative & General	4,699,006			4,699,006

Subtotal	4,699,006	5,183,712	12,790,441	22,673,159

Natural Gas				8,186,048

Total Common Expense				30,859,207

(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, 2023

Item #3

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

Electric:

Depreciation			3,416,786	3,416,786
Amortization			5,673,236	5,673,236
Taxes Other than Income		5,183,712		5,183,712
Administrative & General	4,093,407			4,093,407

Subtotal	4,093,407	5,183,712	9,090,022	18,367,141

Natural Gas				7,225,020

Total Common Expense				25,592,161

(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			2,258,365	2,258,365
Amortization			1,442,054	1,442,054
Taxes Other than Income		—		—
Administrative & General	605,599			605,599

Subtotal	605,599		3,700,419	4,306,018

Natural Gas				656,818

Total Common Expense				4,962,836

(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:

12/31/2023

Year/Period of Report

End of:

2023

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)	32,202,034	30,065,526	43,220,888	25,582,731
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)	28,122,918	30,092,503	43,826,313	23,477,526
4	Transmission Rights
5	Ancillary Services	33,309	25,550	25,273	26,953
6	Other Items (list separately)
7	Day Ahead & Real Time Admin	116,585	89,424	88,456	94,334
8	Market Monitoring & Compliance	16,655	12,775	12,637	13,476
46	TOTAL	60,491,501	60,285,778	87,173,567	49,195,020

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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) 18,266,645	MWh	1,721,705
2	Reactive Supply and Voltage
3	Regulation and Frequency Response				(b) 6,241,734	MWh	1,220,113
4	Energy Imbalance	(c) 29,621,591	MWh	8,867,081
5	Operating Reserve - Spinning				226	MWh	1,410,958
6	Operating Reserve - Supplement				226	MWh	1,333,115
7	Other				(d) 458,613	MWh	22,653,218
8	Total (Lines 1 thru 7)	(e) 29,621,591		8,867,081	24,967,444		28,339,109

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: AncillaryServicesSoldNumberOfUnits

Transmission Customers are billed under the formula rate as approved in FERC docket ER19-1756. For more information see 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	5,199,885	MWh	705,708
Scheduling, System Control and Dispatch Point-to-Point	13,066,760	MWh	1,015,997
	18,266,645		1,721,705

(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	4,292,632	MWh	966,222
Regulation and Frequency Responses Non Ver Network Cust	Schedule 3 Non Ver	1,384	MW	87,381
Regulation and Frequency Response Point to Point Cust	Schedule 3a Ver	24,886	MWh	15,272
Regulation and Frequency Response Point to Point Cust	Schedule 3a Non Ver	1,922,832	MWh	151,238

		6,241,734		1,220,113

Line No 4 Column e: Energy Imbalance is calculated and charged based on Schedules 4, 4a, 9, 9a, and Attachment P of the NorthWestern OATT. For more information see the NorthWestern Energy OATT Schedule 4, 4a and Attachment P see OASIS at https://oasis.oati.com/NWMT

(d) Concept: AncillaryServicesSoldNumberOfUnits

Other Ancillary Services


		Number of Units (e)	Unit of Measure (f)	Dollars (g)
Generation Imbalance	Schedule 9	—	MWh	—
Losses on Load Network Customers		137,398	MWh	11,061,251
Losses on Load Point to Point Customers		296,329	MWh	11,567,644
Flex Reserves	Schedule 11	24,886	MWh	24,323
		458,613		22,653,218

(e) Concept: AncillaryServicesPurchasedNumberOfUnits

This schedule represents Montana Operations only.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	1,939	30	19	1,092	686	275	0	2,567
2	February	2,055	22	19	1,098	784	275	0	1,580
3	March	1,790	8	8	1,097	716	275	0	1,582
4	Total for Quarter 1				3,287	2,186	825	0	5,729
5	April	1,631	4	9	1,096	643	275	0	3,418
6	May	1,524	30	17	1,098	604	275	0	2,089
7	June	1,667	30	17	1,096	640	275	0	1,700
8	Total for Quarter 2				3,290	1,887	825	0	7,207
9	July	2,020	25	19	1,087	713	275	0	3,564
10	August	1,977	17	17	1,084	660	275	0	2,611
11	September	1,620	2	18	1,065	588	275	0	2,509
12	Total for Quarter 3				3,236	1,961	825	0	8,684
13	October	1,703	27	10	1,073	624	275	0	6,804
14	November	1,735	27	18	1,051	690	275	0	3,633
15	December	1,761	26	19	1,032	703	575	0	3,176
16	Total for Quarter 4				3,156	2,017	1,125	0	13,613
17	Total				12,969	8,051	3,600	0	35,233	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:

12/31/2023

Year/Period of Report

End of:

2023

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	285	31	8	0	0	0	299	14	313
2	February	291	22	11	0	0	0	305	14	319
3	March	240	14	8	0	0	0	252	12	264
4	Total for Quarter 1							856	40	896
5	April	212	4	10	0	0	0	223	11	234
6	May	225	30	18	0	0	0	237	12	249
7	June	221	19	17	0	0	0	235	14	249
8	Total for Quarter 2							695	37	732
9	July	259	27	18	0	0	0	271	12	283
10	August	267	22	17	0	0	0	280	13	293
11	September	267	1	18	0	0	0	280	13	293
12	Total for Quarter 3							831	38	869
13	October	323	17	17	0	0	0	335	12	347
14	November	319	28	8	0	0	0	330	11	341
15	December	310	11	8	0	0	0	321	11	332
16	Total for Quarter 4							986	34	1,020
17	Total Year to Date/Year							3,368	149	3,517

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2023-12-31

Year/Period of Report

End of:

2023

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)	8,043,103
3	Steam	2,328,350	23	Requirements Sales for Resale (See instruction 4, page 311.)
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	1,213,387
5	Hydro-Conventional	2,483,047	25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	8,861
7	Other	1,022,472	27	Total Energy Losses	605,615
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	5,833,869	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	9,870,966
10	Purchases (other than for Energy Storage)	4,036,773
10.1	Purchases for Energy Storage	0
11	Power Exchanges:
12	Received	28,874
13	Delivered	28,550
14	Net Exchanges (Line 12 minus line 13)	324
15	Transmission For Other (Wheeling)
16	Received	13,627,348
17	Delivered	13,627,348
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)	9,870,966

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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	719,195	71,778	2,214	30	19
30	February	743,652	68,180	2,330	22	19
31	March	718,921	107,168	2,065	8	8
32	April	727,529	66,596	1,906	4	9
33	May	565,981	112,259	1,799	30	17
34	June	567,285	59,924	1,942	30	17
35	July	651,935	94,666	2,295	25	19
36	August	686,081	123,059	2,252	17	17
37	September	651,188	98,980	1,895	2	18
38	October	632,768	132,185	1,978	27	10
39	November	754,577	129,598	2,010	27	18
40	December	767,789	148,994	2,336	26	19
41	Total	8,186,901	1,213,387
	NAME OF SYSTEM: South Dakota Operations
29	January	172,161	0	285	31	8
30	February	136,588	0	291	22	11
31	March	137,484	0	240	14	8
32	April	178,629	0	212	4	10
33	May	105,555	0	225	30	18
34	June	109,375	0	221	19	17
35	July	116,722	0	259	27	18
36	August	146,121	0	267	22	17
37	September	179,575	0	267	1	18
38	October	156,789	0	323	17	17
39	November	104,707	0	319	28	8
40	December	140,359	0	310	11	8
41	Total	1,684,065	0

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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 Mcf.
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: 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) Steam	Wind Turbine	Wind Turbine	(h) Internal Combustion
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Conventional	Conventional	Wind Turbine	Conventional	Conventional	Boiler	Conventional	Conventional	Conventional	Wind Turbine	Wind Turbine	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1978	2013	2015	1975	2022	1984	1981	2010	1979	2012	2014	1974
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1978	2013	2015	1975	2022	1986	1981	2010	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	(i) 203.25	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	55	40	11	13
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	0	1,470	8,760	6,606	4,533	7,996	7,841	8,759	2,648	8,758	8,760	0
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	0	0	79	0	56	0	0	150	0	40	11.28	0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	(j) 28	60	0	111	56	222	43	150	55	0	0	13
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	(k) 21	52	0	110	56	(l) 0	43	150	55	0	0	13
11	PlantAverageNumberOfEmployees Average Number of Employees	0	9	5	(m) 0	5	(n) 0	(o) 0	11	(p) 0	(q) 0	(r) 0	0
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	5,000	39,557,000	273,688,000	320,588,000	89,326,000	1,648,505,000	253,241,000	474,945,000	106,016,000	112,224,000	33,126,000	(s) 280,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	1,314	36,647		162,629	192,378	446,126	203,882	1,893,984		111,793	8,119,540	9,631
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	29,021	10,385,543	14,557,823	9,942,028	730,818	28,213,948	10,050,056	22,122,874	7,749,719	29,187,825		348,247
15	CostOfEquipmentSteamProduction Equipment Costs	3,775,985	38,128,471	100,039,926	146,591,390	86,303,791	88,685,844	42,376,326	147,295,000	56,381,658	53,900,546	11,440,693	7,790,041
16	AssetRetirementCostsSteamProduction Asset Retirement Costs			1,351,541	308,664		21,353,489	1,412,834		302,405	2,913,993	772,822
17	CostOfPlant Total cost (total 13 thru 20)	3,806,320	48,550,660	115,949,290	157,004,711	87,226,987	138,699,407	54,043,098	171,311,858	64,433,782	86,114,157	20,333,055	8,147,919
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	132.1639	590.6406	1,449.3661	1,278.020	1,491.0596	574.3247	1,185.6757	842.8628	1,159.7153	2,152.8539	1,802.5758	602.2113
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr		21,051	70,293	287,727	41,361	53,473	248,576	386,880	193,028	57,362	41,467	352
20	FuelSteamPowerGeneration Fuel		2,313,704		8,578,499	2,911,864	36,168,095	6,575,686	17,303,922	2,900,528			776
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses				464,298		1,394,076	411,445		501,138
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses		640,967	3,322,325	338,856	1,259,399	403,193	222,618	1,815,399	2,011	2,210,741	659,306	10,719
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses				775,672		2,839,102	205,194		367,086
27	RentsSteamPowerGeneration Rents							1,368		28,543
28	Allowances Allowances
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering		21,051		180,358	41,361	270,438	95,676		349,808			352
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures			105,114	129,994		734,202	122,361		76,221
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant				1,079,330		4,974,170	784,333		461,445
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant		530,115		752,267	433,091	531,996	62,602	1,328,808	166,952	64,687	940	20,947
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant			52,600	203,520		478,816	161,974		190,810
34	PowerProductionExpensesSteamPower Total Production Expenses		3,526,888	3,550,332	12,790,521	4,687,076	47,847,561	8,891,833	20,835,009	5,237,570	2,332,790	701,713	33,146
35	ExpensesPerNetKilowattHour Expenses per Net kWh		0.0892	0.0130	0.0399	0.0525	0.0290	0.0351	0.0439	0.0494	0.0208	0.0212

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	Neal	Neal	Yankton
36	FuelKind Fuel Kind	Oil	Gas	Coal	Oil	Other	Gas	Coal	Oil	Coal	Oil	Other	Gas	Oil	Coal	Oil	Oil
37	FuelUnit Fuel Unit	bbl	MMBTU	T	bbl	T	MMBTU	T	bbl	T	bbl	T	MMBTU	bbl	T	bbl	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	0	419,578	230,445	3,836	406,911	736,222	1,031,554	2,548	219,339	951	1,483	6,128,106	10	63,876	1,966	0
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	138,000	1,000	4,795	140,000	0	1,000	8,614	140,000	6,963	140,000	0	1,000	140,000	8,593	139,000	138,000
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year		3.882	33.697	69.554	220.787	3.688	34.704	144.993	28.099	125.363	141.581	2.800	127.750	39.996	131.226
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned		3.882	33.697	69.554	220.787	3.688	34.704	144.993	28.099	125.363	141.581	2.800	127.750	39.996	131.226
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU		37.478	3.514	11.829		3.688	2.014	24.659	2.018	21.320		2.779	21.727	2.327	22.478
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen		(t) 0.058	(u) 0.027			(v) 0.033	(w) 0.022		(x) 0.026				(y) 0.036	(z) 0.027
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation		(aa) 10,606.922	(ab) 6,963.477			(ac) 8,241.968	(ad) 10,789.533		(ae) 12,082.914				(af) 12,902.888	(ag) 11,166.788

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2023

Year/Period of Report

End of:

2023

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

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.

(h) Concept: PlantKind

Designed for peak load service.

(i) 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.

(j) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater

Site 40 F., Base

(k) Concept: NetContinuousPlantCapabilityLimitedByCondenserWater

Site 80 F., Base

(l) Concept: NetContinuousPlantCapabilityLimitedByCondenserWater

When Limited by Condensor Water with "No Limitation."

(m) Concept: PlantAverageNumberOfEmployees

All plant employees are employed by the plant operator, Otter Tail Power Co.

(n) Concept: PlantAverageNumberOfEmployees

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

(o) Concept: PlantAverageNumberOfEmployees

All plant employees are employed by the plant operator, Otter Tail Power Co.

(p) Concept: PlantAverageNumberOfEmployees

All plant employees are employed by the plant operator, Mid American Energy

(q) Concept: PlantAverageNumberOfEmployees

All employees are contracted through General Electric as plant operator

(r) Concept: PlantAverageNumberOfEmployees

All employees are contracted through General Electric as plant operator

(s) Concept: NetGenerationExcludingPlantUse

Station power use exceeded generation.

(t) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(u) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(v) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(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: AverageBritishThermalUnitPerKilowattHourNetGeneration