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Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
__________________________________
FORM 10-Q
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2024
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 333-212006
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.
(Exact name of registrant as specified in its charter)
Colorado84-0464189
(State or other jurisdiction of incorporation or
organization)
(I.R.S. employer identification
number)
1100 West 116th Avenue
Westminster,Colorado80234
(Address of principal executive offices)
(Zip Code)
(303) 452-6111
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  No  (Note: The registrant is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), but voluntarily files reports with the Securities and Exchange Commission).
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes  No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer Accelerated filer
Non-accelerated Filer Smaller reporting company Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No 
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
NoneNoneNone
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. The registrant is a membership corporation and has no authorized or outstanding equity securities.


Table of Contents
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2024
Page Number

i

Table of Contents
GLOSSARY
The following abbreviations and acronyms used in this quarterly report on Form 10-Q are defined below:
Abbreviations or AcronymsDefinition
2022 Revolving Credit AgreementAmended and Restated Credit Agreement, dated as of April 25, 2022, between us and CFC, as administrative agent
2023 ERPour 2023 Electric Resource Plan filed with the COPUC
ASCAccounting Standards Codification
ASUAccounting Standards Update
BasinBasin Electric Power Cooperative
BoardBoard of Directors
CFCNational Rural Utilities Cooperative Finance Corporation
CoBankCoBank, ACB
Colowyo CoalColowyo Coal Company L.P., a subsidiary of ours
COPUCColorado Public Utilities Commission
D.C. Circuit Court of AppealsUnited States Court of Appeals for the District of Columbia Circuit
DSRDebt Service Ratio (as defined in our Master Indenture)
ECREquity to Capitalization Ratio (as defined in our Master Indenture)
EPAEnvironmental Protection Agency
FERCFederal Energy Regulatory Commission
FitchFitch Ratings Inc.
FPAFederal Power Act, as amended
GAAPAccounting principles generally accepted in the United States
kWhkilowatt hour
LPEALa Plata Electric Association, Inc.
Master IndentureMaster First Mortgage Indenture, Deed of Trust and Security Agreement, dated effective as of December 15, 1999, between us and U.S. Bank Trust Company, National Association, as successor trustee
MBPPMissouri Basin Power Project
Membersour Utility Members and Non-Utility Members
MPEIMountain Parks Electric, Inc.
Moody’sMoody’s Investors Services, Inc.
MWmegawatt
MWhmegawatt hour
Non-Utility Membersour non-utility members
NRPPDNorthwest Rural Public Power District
New ERA ProgramUSDA's Empowering Rural America Program
OATTOpen Access Transmission Tariff
RUSRural Utilities Service
S&PS & P Global Ratings
SECSecurities and Exchange Commission
Springerville PartnershipSpringerville Unit 3 Partnership LP, a subsidiary of ours
Springerville Unit 3Springerville Generating Station Unit 3
Term SOFRthe implied rate on the future movement in the Secured Overnight Financing Rate (or "SOFR") over a future reference period
Tri-State, We, Our, Us, the AssociationTri-State Generation and Transmission Association, Inc.
United PowerUnited Power, Inc.
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USDAUnited States Department of Agriculture
Utility Membersour electric distribution member systems, consisting of both Class A members and Class B members
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FORWARD-LOOKING STATEMENTS
This quarterly report on Form 10-Q contains “forward-looking statements.” All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy, member withdraws and development, construction, operation, or closure of facilities (often, but not always, identified through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “forecast,” “projection,” “target” and “outlook”) are forward-looking statements.
Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Tri-State Generation and Transmission Association, Inc.
Consolidated Statements of Financial Position (Unaudited)
(dollars in thousands)
September 30, 2024December 31, 2023
ASSETS
Property, plant and equipment
Electric plant
In service$5,698,894 $5,722,679 
Construction work in progress273,339 163,954 
Total electric plant5,972,233 5,886,633 
Less allowances for depreciation and amortization(2,805,718)(2,739,924)
Net electric plant3,166,515 3,146,709 
Other plant963,871 952,318 
Less allowances for depreciation, amortization and depletion(743,752)(711,896)
Net other plant220,119 240,422 
Total property, plant and equipment3,386,634 3,387,131 
Other assets and investments
Investments in other associations185,673 187,684 
Investments in and advances to coal mines1,721 1,619 
Restricted cash and investments2,295 3,408 
Other noncurrent assets14,812 15,264 
Total other assets and investments204,501 207,975 
Current assets
Cash and cash equivalents293,578 106,005 
Restricted cash and investments17,577 605 
Short-term investments95,000  
Deposits and advances78,977 37,455 
Accounts receivable—Utility Members92,299 101,394 
Other accounts receivable44,457 23,123 
Coal inventory75,062 54,979 
Materials and supplies112,900 106,893 
Total current assets809,850 430,454 
Deferred charges
Regulatory assets826,476 919,483 
Prepayment—NRECA Retirement Security Plan1,343 5,372 
Other52,501 36,121 
Total deferred charges880,320 960,976 
Total assets$5,281,305 $4,986,536 
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity$942,654 $984,581 
Accumulated other comprehensive loss(596)(839)
Noncontrolling interest130,453 134,269 
Total equity1,072,511 1,118,011 
Long-term debt2,696,693 2,896,506 
Total capitalization3,769,204 4,014,517 
Current liabilities
Utility Member advances11,079 14,333 
Accounts payable179,118 123,674 
Short-term borrowings74,627 184,305 
Accrued expenses21,940 39,268 
Current asset retirement obligations16,337 21,635 
Accrued interest42,930 24,549 
Accrued property taxes29,506 31,986 
Current maturities of long-term debt192,561 223,523 
Total current liabilities568,098 663,273 
Deferred credits and other liabilities
Regulatory liabilities584,375 2,317 
Deferred income tax liability14,609 15,223 
Asset retirement and environmental reclamation obligations219,995 195,566 
Other114,076 84,125 
Total deferred credits and other liabilities933,055 297,231 
Accumulated postretirement benefit and postemployment obligations10,948 11,515 
Total equity and liabilities$5,281,305 $4,986,536 
The accompanying notes are an integral part of these consolidated financial statements.
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Tri-State Generation and Transmission Association, Inc.
Consolidated Statements of Operations (Unaudited)
(dollars in thousands)
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
Operating revenues
Utility Member electric sales$309,599 $357,576 $863,711 $923,977 
Non-member electric sales73,943 51,294 148,330 111,729 
Rate stabilization108,222 14,041 125,123 36,862 
Provision for rate refunds (210) 94 
Other37,119 15,618 80,767 48,162 
528,883 438,319 1,217,931 1,120,824 
Operating expenses
Purchased power123,437 120,250 315,347 316,356 
Fuel59,271 71,241 167,819 197,944 
Production40,192 44,758 129,375 142,733 
Transmission47,984 47,098 140,506 142,406 
General and administrative32,430 19,663 77,993 61,738 
Depreciation, amortization and depletion60,277 43,120 149,053 128,191 
Coal mining3,238 3,834 5,343 9,603 
Goodwill impairment68,223  68,223  
Other4,471 2,345 10,671 11,057 
439,523 352,309 1,064,330 1,010,028 
Operating margins89,360 86,010 153,601 110,796 
Other income
Interest5,015 2,343 11,455 5,153 
Capital credits from cooperatives1,017 1,145 2,298 3,103 
Other income669 3,852 4,792 5,894 
6,701 7,340 18,545 14,150 
Interest expense
Interest43,587 45,558 133,292 128,924 
Interest charged during construction(3,279)(1,238)(7,876)(3,328)
40,308 44,320 125,416 125,596 
Income tax expense  23  67 
Net margins including noncontrolling interest55,753 49,007 46,730 (717)
Net margin attributable to noncontrolling interest(960)(2,526)(6,457)(7,444)
Net margins attributable to the Association$54,793 $46,481 $40,273 $(8,161)
The accompanying notes are an integral part of these consolidated financial statements.
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Tri-State Generation and Transmission Association, Inc.
Consolidated Statements of Comprehensive Income (Loss) (Unaudited)
(dollars in thousands)
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
Net margins including noncontrolling interest$55,753 $49,007 $46,730 $(717)
Other comprehensive income (loss):
Unrealized gain on securities available for sale110 10 175 26 
Amortization of prior service credit on postretirement benefit obligation included in net margin(125)(409)(661)(1,228)
Amortization of prior service cost on executive benefit restoration obligation included in net margin220 289 729 867 
Other comprehensive income (loss)205 (110)243 (335)
Comprehensive income (loss) including noncontrolling interest55,958 48,897 46,973 (1,052)
Net comprehensive income attributable to noncontrolling interest(960)(2,526)(6,457)(7,444)
Comprehensive income (loss) attributable to the Association$54,998 $46,371 $40,516 $(8,496)
The accompanying notes are an integral part of these consolidated financial statements.
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Tri-State Generation and Transmission Association, Inc.
Consolidated Statements of Equity (Unaudited)
(dollars in thousands)
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
Patronage capital equity at beginning of period$887,861 $930,223 $984,581 $984,865 
Net margins attributable to the Association54,793 46,481 40,273 (8,161)
Retirement of patronage capital  (82,200) 
Patronage capital equity at end of period942,654 976,704 942,654 976,704 
Accumulated other comprehensive loss at beginning of period(801)(693)(839)(468)
Unrealized gain on securities available for sale110 10 175 26 
Reclassification adjustment of prior service credit on postretirement benefit obligation included in net margin(125)(409)(661)(1,228)
Reclassification adjustment for prior service cost on executive benefit restoration obligation included in net margin220 289 729 867 
Accumulated other comprehensive loss at end of period(596)(803)(596)(803)
Noncontrolling interest at beginning of period129,738 130,149 134,269 126,180 
Net comprehensive income attributable to noncontrolling interest960 2,526 6,457 7,444 
Equity distribution to noncontrolling interest(245)(933)(10,273)(1,882)
Noncontrolling interest at end of period130,453 131,742 130,453 131,742 
Total equity at end of period$1,072,511 $1,107,643 $1,072,511 $1,107,643 
The accompanying notes are an integral part of these consolidated financial statements.

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Tri-State Generation and Transmission Association, Inc.
Consolidated Statements of Cash Flows (Unaudited)
(dollars in thousands)

Nine Months Ended September 30,
20242023
Operating activities
Net margins including noncontrolling interest$46,730 $(717)
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion149,053 128,191 
Amortization of NRECA Retirement Security Plan prepayment4,029 4,029 
Amortization of debt issuance costs1,992 1,801 
Goodwill impairment68,223  
Deposits associated with generator interconnection requests26,232 11,601 
Rate stabilization revenue(125,123)(36,862)
Capital credit allocations from cooperatives and income from coal mines under refund distributions1,909 1,263 
Changes in operating assets and liabilities:
Accounts receivable(9,628)4,389 
Coal inventory(20,083)(16,875)
Materials and supplies(6,006)(9,446)
Accounts payable and accrued expenses14,706 1,078 
Accrued interest18,381 17,290 
Accrued property taxes(2,479)(6,301)
Deferred membership withdrawal709,395  
Other(12,178)5,271 
Net cash provided by operating activities865,153 104,712 
Investing activities
Purchases of plant(199,574)(119,081)
Sale of electric plant75,000  
Sale of non-utility assets3,136  
Purchase of investments(95,000) 
Changes in deferred charges(1,757)2,078 
Net cash used in investing activities(218,195)(117,003)
Financing activities
Changes in Member advances(3,255)3,416 
Payments of long-term debt(232,272)(81,010)
Proceeds from issuance of long-term debt 450,000 
Debt issuance costs(8)(605)
Change in short-term borrowings, net(109,777)(273,502)
Retirement of patronage capital(87,414)(5,446)
Equity distribution to noncontrolling interest(10,273)(1,882)
Other(527)(482)
Net cash provided by (used in) financing activities(443,526)90,489 
Net increase in cash, cash equivalents and restricted cash and investments203,432 78,198 
Cash, cash equivalents and restricted cash and investments – beginning110,018 110,682 
Cash, cash equivalents and restricted cash and investments – ending$313,450 $188,880 
Supplemental cash flow information:
Cash paid for interest$105,701 $108,407 
Cash paid for income taxes$ $ 
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable$ $(395)
The accompanying notes are an integral part of these consolidated financial statements.
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Tri-State Generation and Transmission Association, Inc.
Notes to Unaudited Consolidated Financial Statements
For the Three and Nine Months Ended September 30, 2024 and 2023
NOTE 1 – PRESENTATION OF FINANCIAL INFORMATION
The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2023 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Our consolidated financial position as of September 30, 2024, results of operations for the three and nine months ended September 30, 2024 and 2023, and cash flows for the nine months ended September 30, 2024 and 2023 are not necessarily indicative of the results that may be expected for an entire year or any other period.
Basis of Consolidation
We are a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis serving large portions of Colorado, Nebraska, New Mexico and Wyoming. We were incorporated under the laws of the State of Colorado in 1952. We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. We have forty-one electric distribution member systems who are Class A members to which we provided electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members (“Non-Utility Members”). Our Class A members and any Class B members are collectively referred to as our “Utility Members.” Our Class A members, any Class B members, and Non-Utility Members are collectively referred to as our “Members.” Our rates are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). On December 23, 2019, our stated rate (A-40) to our Class A members was filed at FERC and was accepted by FERC on March 20, 2020. On August 2, 2021, FERC approved our settlement agreement related to our stated rate to our Class A members. On July 30, 2024, FERC issued an order accepting our A-41 formula rate to our Class A members, effective August 1, 2024, subject to refund. FERC further set our A-41 rate filing for settlement and hearing procedures and confirmed our accounting treatment, including amortization, and creation of regulatory assets for Escalante Generating Station, Rifle Generating Station, Craig Generating Station Units 2 and 3 and the New Horizon Mine environmental obligation. However, FERC did not authorize us to recover the regulatory assets that represent acquisition costs/goodwill for J.M Shafer Generating Station and Colowyo Coal Company LP (“Colowyo Coal”). See Note 2 - Accounting for Rate Regulation. These costs were on our books prior to us becoming subject to FERC's jurisdiction. FERC stated in its order accepting our A-41 rate schedule that we did not request express authorization to recover acquisition costs including goodwill in our rates. Therefore, we wrote off the J.M Shafer Generating Station and Colowyo Coal acquisition costs/goodwill in September 2024 which resulted in the recognition of expense of $68.2 million. We recognized deferred membership withdrawal income in September 2024 as part of our rate stabilization measures, therefore, the write off of the J.M. Shafer Generating Station and Colowyo acquisition costs/goodwill resulted in no impact to our Utility Members' wholesale rate.
On May 1, 2024, United Power, Inc. (“United Power") withdrew from membership in us and terminated their wholesale electric service contract with us pursuant to Rate Schedule 281 (contract termination payment methodology) on-file with FERC and a Membership Withdrawal Agreement with United Power. United Power’s contract termination payment amount was $709.4 million. United Power paid us an exit fee in cash of $627.2 million, after a regulatory liabilities credit and United Power relinquishing their right to any patronage capital in us resulting in a discounted patronage capital credit of $82.2 million. Such amounts remain subject to true up in accordance with Rate Schedule 281 and United Power's Membership Withdrawal Agreement. Of the total contract termination payment, $530.1 million was membership withdrawal that was deferred as a regulatory liability. The remaining $179.3 million of United Power's contract termination payment related to a transmission credit for the portion of transmission debt allocated to United Power that was deferred as required by FERC's order on our Rate Schedule 281.
We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with GAAP, the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.
The accompanying financial statements reflect the consolidated accounts of Tri-State Generation and Transmission Association, Inc. (“Tri-State”, “we”, “our”, “us” or “the Association”), our wholly-owned and majority-owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 17 – Variable Interest
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Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. We have eliminated all intercompany balances and transactions in consolidation.
Accounting Pronouncement - Not Yet Adopted
In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2023-09 – Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The purpose of ASU 2023-09 is to enhance the transparency and decision usefulness of income tax disclosures by providing additional information related to the following:
(1) Rate reconciliation: ASU 2023-09 requires a tabular rate reconciliation using both percentages and dollar amounts of the reported income tax expense (or benefit) from continuing operations to the product of income (or loss) from continuing operating before income taxes and the applicable statutory federal income tax rate of the county of domicile using specific categories. The following specific categories are required to be disclosed in the rate reconciliation; state and local income tax (qualitative disclosure required for states that make up over 50% of this category), foreign tax effect, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, changes in unrecognized tax benefits, and any other item that meets the 5 percent threshold.
(2) Income taxes paid: ASU 2023-09 requires all reporting entities to disclose the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign jurisdictions. It also requires additional disaggregation of income taxes paid to an individual jurisdiction equal to or greater than 5 percent of total income taxes paid (net of refunds). Entities are required to disclose pre-tax income (or loss) from continuing operations disaggregated by domestic and foreign along with income tax expense (or benefit) disaggregated by federal, state, and foreign components.
ASU 2023-09 is effective for public business entities for annual periods beginning after December 15, 2024, with early adoption and retrospective or prospective application permitted. We have evaluated the impact of ASU 2023-09 and believe that the adoption of this update will not have a material impact on our consolidated financial statement disclosures.
NOTE 2 – ACCOUNTING FOR RATE REGULATION
In accordance with the accounting requirements related to regulated operations, some revenues and expenses have been deferred at the discretion of our Board, subject to FERC approval, if based on regulatory orders or other available evidence, it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs that we expect to recover from our Utility Members based on rates approved by the applicable authority. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Utility Members based on rates approved by the applicable authority. Expected recovery of deferred costs and returning deferred credits are based on specific ratemaking decisions by FERC or precedent for each item. We recognize regulatory assets as expenses and regulatory liabilities as operating revenue, other income, or a reduction in expense concurrent with their recovery through rates.
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Regulatory assets and liabilities are as follows (dollars in thousands):
September 30,
2024
December 31,
2023
Regulatory assets
Deferred income tax expense (1)$14,609 $15,223 
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)72,833 74,551 
Acquisition costs – J.M. Shafer (3) 37,749 
Acquisition costs – Colowyo Coal (4) 33,062 
Deferred debt prepayment transaction costs (5)99,946 106,417 
Deferred Holcomb expansion impairment loss (6)71,289 74,795 
New Horizon Mine environmental obligation (7)44,570 44,869 
Unrecovered plant (8)523,229 532,817 
Total regulatory assets826,476 919,483 
Regulatory liabilities
Interest rate swap - realized gain (9) and other1,507 1,854 
Membership withdrawal (10)405,478 463 
Withdrawal related transmission credit (11)177,390  
Total regulatory liabilities584,375 2,317 
Net regulatory asset$242,101 $917,166 
(1)A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.
(2)Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members through rates.
(3)Represented acquisition costs related to our acquisition of an entity that owned J.M. Shafer Generating Station in December 2011. In September 2024, we wrote off the remaining $35.8 million balance of J.M. Shafer Generating Station acquisition costs as they are no longer probable to be recovered, offset with recognition of previously deferred membership withdrawal income. See Note 1 - Presentation of Financial Information.
(4)Represented acquisition costs related to our acquisition of Colowyo Coal in December 2011. In September 2024, we wrote off the remaining $32.4 million balance of Colowyo Coal acquisition costs as they are no longer probable to be recovered, offset with recognition of previously deferred membership withdrawal income. See Note 1 - Presentation of Financial Information.
(5)Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Utility Members through rates.
(6)Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. The regulatory asset for the deferred impairment loss is being amortized to depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates.
(7)Represents $44.6 million of New Horizon Mine environmental obligation expense that was recognized as a regulatory item in 2023. The regulatory asset for the deferred environmental obligation expense is being amortized to depreciation, amortization and depletion expense in the amount of $1.8 million annually over 25 years ending in 2049 and recovered from our Utility Members through rates.
(8)Represents deferral of the impairment losses and other closure costs related to the early retirement of the Escalante, Rifle and Craig Generating Station Units 2 and 3. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $12.2 million annually over the 25-year period ending in December 2045, which was the depreciable life of the Escalante Generating Station, and recovered from our Utility Members through rates. The deferred impairment loss for Rifle Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $0.6 million annually through December 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates. We recognized the early retirement of Craig Generating Station Units 2 and 3. We recognized an impairment loss of $261.6 million and
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deferred the loss in accordance with accounting for rate regulation. The deferred impairment loss will be amortized to depreciation, amortization and depletion expense beginning in October 2028 through 2039 for Craig Generating Station Unit 2 and January 2030 through 2043 for Craig Generating Station Unit 3 and will be recovered from our Utility Members through future rates. These amortization periods are the depreciable lives of Craig Generating Station Unit 2 and 3. The annual amortization is expected to approximate the former annual Craig Generation Station Unit 2 and 3 depreciation for the remaining life of the asset.
(9)Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12–year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods.
(10) Represents the remaining balance of the deferred recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. On May 1, 2024, United Power withdrew from membership in us and United Power's contract termination payment amount was $709.4 million, of which $530.1 million was membership withdrawal that was deferred by our Board as a regulatory liability. The deferred membership withdrawal will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods with the oldest vintage year used first.
(11) Represents the remaining amount of United Power's transmission credit related to taking transmission service from us. A portion of a withdrawing member's contract termination payment is allocated to transmission debt that is deferred as required by FERC's order on Rate Schedule 281. The transmission credit, plus interest at FERC's prescribed interest rate, is refunded to the withdrawing member on a monthly basis if the withdrawing member takes transmission service from us and amortized on a straight-line basis over the remaining term. If the withdrawing member's transmission bill for a given month is lower than the credit amount that would be due, the difference is forfeited by the withdrawing member.
NOTE 3 – PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment consists of electric plant and other plant. Both of these are discussed below and are included on our consolidated statements of financial position.
ELECTRIC PLANT:  As of September 30, 2024, our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight‑line method are as follows (dollars in thousands):
Annual Depreciation RatePlant In
Service
Accumulated
Depreciation
Net Book
Value
Generation plant1.14 %to4.14 %$3,098,909 $(1,721,383)$1,377,526 
Transmission plant1.17 %to1.84 %1,929,078 (706,983)1,222,095 
General plant1.20 %to11.60 %430,202 (279,264)150,938 
Other2.75 %to10.00 %240,705 (98,088)142,617 
Electric plant in service (at cost)$5,698,894 $(2,805,718)2,893,176 
Construction work in progress273,339 
Electric plant$3,166,515 

In March 2024, we executed an asset purchase agreement to purchase the 145 MW Axial Basin Solar project being developed in northwestern Colorado. Concurrent with execution of the purchase agreement, we also executed an engineering, procurement and construction contract with an affiliate of the developer of the project. In April 2024, we closed on the acquisition of Axial Basin Solar project and issued a notice to proceed with construction to the contractor. Additionally, in April 2024, we executed an asset purchase agreement to purchase the 110 MW Dolores Canyon Solar project being developed in southwestern Colorado. Concurrent with execution of the purchase agreement, we also executed an engineering, procurement and construction contract with an affiliate of the developer of the project. In May 2024, we closed on the acquisition of Dolores Canyon Solar project and issued a notice to proceed with construction to the contractor.

Both acquisitions were accounted for as an asset acquisition in accordance with the accounting requirements for business combinations since we purchased the project assets and not a business. As such, the asset acquisitions and subsequent
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facility development costs are being capitalized which is included in construction work in progress as of September 30, 2024. Both projects are expected to achieve commercial operation in the second half of 2025.
As of December 31, 2023, our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight‑line method are as follows (dollars in thousands):
Annual Depreciation RatePlant In
Service
Accumulated
Depreciation
Net Book
Value
Generation plant0.89 %to6.27 %$3,082,133 $(1,669,941)$1,412,192 
Transmission plant1.11 %to2.09 %1,983,629 (708,412)1,275,217 
General plant1.46 %to9.53 %410,856 (266,013)144,843 
Other2.75 %to10.00 %246,061 (95,558)150,503 
Electric plant in service (at cost)$5,722,679 $(2,739,924)2,982,755 
Construction work in progress163,954 
Electric plant$3,146,709 
JOINTLY OWNED FACILITIES:  Our share in each jointly owned facility is as follows as of September 30, 2024 (these electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant table above) (dollars in thousands):
Tri-State
Share
Electric
Plant in
Service
Accumulated
Depreciation
Construction
Work In
Progress
Yampa Project - Craig Generating Station Units 1 and 224.00 %$392,510 $365,379 $ 
MBPP - Laramie River Station28.50 %545,456 351,886 8,928 
Total$937,966 $717,265 $8,928 
OTHER PLANT:  Other plant consists of mine assets (discussed below) and non‑utility assets which consist of facilities not in service, land and irrigation equipment.
We own 100 percent of Elk Ridge Mining and Reclamation, LLC (“Elk Ridge”), organized for the purpose of acquiring coal reserves and supplying coal to us. Elk Ridge is the owner of the Colowyo Mine, a surface coal mine near Craig, Colorado, and the New Horizon Mine near Nucla, Colorado. The New Horizon Mine is in post-reclamation monitoring and no longer produces coal. The expenses related to the Colowyo Mine coal used by us are included in fuel expense on our consolidated statements of operations.
Other plant assets are as follows (dollars in thousands):
September 30,
2024
December 31,
2023
Colowyo Mine assets$408,359 $396,441 
New Horizon Mine assets6,287 6,448 
Accumulated depreciation and depletion(216,142)(184,239)
Net mine assets198,504 218,650 
Non-utility assets549,225 549,430 
Accumulated depreciation(527,610)(527,658)
Net non-utility assets21,615 21,772 
Net other plant$220,119 $240,422 
NOTE 4 – INVESTMENTS IN OTHER ASSOCIATIONS
Investments in other associations include investments in the patronage capital of other cooperatives and other required investments in the organizations. Our investment in a cooperative increases when a cooperative allocates patronage capital credits to us and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative.
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Investments in other associations are as follows (dollars in thousands):
September 30,
2024
December 31,
2023
Basin Electric Power Cooperative$135,652 $135,652 
National Rural Utilities Cooperative Finance Corporation - patronage capital12,599 12,451 
National Rural Utilities Cooperative Finance Corporation - capital term certificates15,054 15,054 
CoBank, ACB16,946 18,809 
Other5,422 5,718 
Investments in other associations$185,673 $187,684 
Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during the nine months ended September 30, 2024 or during 2023.
NOTE 5 – CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS
We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity.
Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds are amounts that have been restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on our consolidated statements of financial position. The other funds are for amounts restricted by contract or other legal reasons that are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on our consolidated statements of financial position.
The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands):
September 30,
2024
December 31,
2023
Cash and cash equivalents$293,578 $106,005 
Restricted cash and investments - current17,577 605 
Restricted cash and investments - noncurrent2,295 3,408 
Cash, cash equivalents and restricted cash and investments$313,450 $110,018 
NOTE 6 – CONTRACT ASSETS AND CONTRACT LIABILITIES
Accounts Receivable
We record accounts receivable for our unconditional rights to consideration arising from our performance under contracts with our Members and other parties. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible. See Note 13 – Revenue.
Contract liabilities (unearned revenue)
A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in unearned revenue (included in other deferred credits and other liabilities on our consolidated statements of financial position) before revenue is recognized, resulting in contract liabilities. During the nine months ended September 30, 2024, we recognized $0.9 million of this unearned revenue in other operating revenues on our consolidated statements of operations.
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Our contract assets and liabilities consist of the following (dollars in thousands):
September 30,
2024
December 31,
2023
Accounts receivable - Utility Members$92,299 $101,394 
Other accounts receivable - trade:
Non-member electric sales22,954 9,657 
Other8,023 11,077 
Total other accounts receivable - trade30,977 20,734 
Other accounts receivable - nontrade13,480 2,389 
Total other accounts receivable$44,457 $23,123 
Contract liabilities (unearned revenue)$3,284 $4,159 
NOTE 7 – OTHER DEFERRED CHARGES
The following other deferred charges are reflected on our consolidated statements of financial position (dollars in thousands):
September 30,
2024
December 31,
2023
Preliminary surveys and investigations$14,946 $12,845 
Advances to operating agents of jointly owned facilities8,457 2,750 
Lease right-of-use assets10,280 6,477 
Other18,818 14,049 
Total other deferred charges$52,501 $36,121 
We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account or the expense could be deferred as a regulatory asset to be recovered from our Utility Members through rates subject to approval by our Board and FERC.
We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project including MBPP – Laramie River Station, and Yampa Project – Craig Generating Station Units 1 and 2. We also make advance payments to the operating agent of Springerville Unit 3.
A right-of-use asset represents a lessee’s right to control the use of the underlying asset for the lease term. Right-of-use assets are included in other deferred charges and presented net of accumulated amortization. See Note 15 – Leases.
NOTE 8 – LONG-TERM DEBT
We have $2.7 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement (“Master Indenture”). Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a debt service ratio ("DSR") requirement on an annual basis and an equity to capitalization ratio ("ECR") requirement of at least 18 percent at the end of each fiscal year. Other than long-term debt for the Springerville certificates that has a DSR requirement of at least 1.02 on an annual basis, all other long-term debt contains a DSR requirement of at least 1.10 on an annual basis. A DSR below 1.025 under the Master Indenture would require us to transfer all cash to a special fund managed by the trustee of the Master Indenture.
We have a secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation (“CFC”), as lead arranger and administrative agent, in the amount of $520 million (“2022 Revolving Credit Agreement”) that expires on April 25, 2027 and includes a swingline sublimit of $125 million, a letter of credit sublimit of $75 million, and a commercial
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paper back-up sublimit of $500 million. As of September 30, 2024, we had $445 million in availability (including $425 million under the commercial paper back-up sublimit) under the 2022 Revolving Credit Agreement.
Long-term debt consists of the following (dollars in thousands):
September 30,
2024
December 31,
2023
Total debt$2,905,162 $3,137,534 
Less debt issuance costs(17,739)(19,723)
Less debt discounts(8,456)(8,678)
Plus debt premiums10,287 10,896 
Total debt adjusted for debt issuance costs, discounts and premiums2,889,254 3,120,029 
Less current maturities(192,561)(223,523)
Long-term debt$2,696,693 $2,896,506 
We entered into both a loan agreement and security agreement, dated October 1, 2024, with the Rural Utilities Service (“RUS”), a part of the United States Department of Agriculture (“USDA”), for a $75 million zero percent interest loan. The loan agreement includes financial DSR requirements in line with the covenants contained in our Master Indenture. This loan was provided by RUS as part of the Rural Energy Savings Program pursuant to the Farm Security and Rural Investment Act of 2002. We can draw up to $50 million of this loan as part of our new Electrify and Save® On-Bill Repayment Program that allows our Utility Members’ customers to install energy efficiency measures, at no up-front cost, and repay over time through their monthly utility bill from our Utility Members the costs of the measures and installation, at low interest rates. The remaining $25 million may be used as permitted in our work plan with RUS. Other than a special draw of $3 million that is due at maturity, each draw must be repaid within 10 years. The loan has a final maturity of October 1, 2044 and is not secured under our Master Indenture, but rather secured by certain depository accounts related to the On-Bill Repayment Program and certain rights in our On-Bill Repayment Program.
As a requirement of the loan from RUS, we must maintain a letter of credit for the benefit of RUS equal to 50 percent of the amount drawn and outstanding from the loan. We expect to make an initial special draw of $3 million and have provided RUS a letter of credit for $3 million issued under our 2022 Revolving Credit Agreement for the $3 million special draw and expected upcoming draws as part of our On-Bill Repayment Program.
NOTE 9 – SHORT-TERM BORROWINGS
We have a commercial paper program under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper back-up sublimit under our 2022 Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our 2022 Revolving Credit Agreement. The commercial paper issuances are used to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances vary but may not exceed 397 days from the date of issue. The commercial paper notes are classified as current and are included in current liabilities as short-term borrowings on our consolidated statements of financial position.
Short-term borrowings consisted of the following (dollars in thousands):
September 30,
2024
December 31,
2023
Commercial paper outstanding, net of discounts$74,527 $184,205 
Short-term borrowings - other$100 $100 
Weighted average interest rate5.14 %5.62 %

As of September 30, 2024, we had $75 million commercial paper outstanding and $425 million of the commercial paper back-up sublimit remained available under the 2022 Revolving Credit Agreement. See Note 8 – Long-Term Debt.
NOTE 10 – ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS
We account for current obligations associated with the future retirement of tangible long-lived assets and environmental reclamation in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long-lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long-lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long-lived asset is depreciated in a
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manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, we determine fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk-free rate and market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability.
Environmental reclamation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred. Such cost estimates may include ongoing care, maintenance and monitoring costs. Changes in reclamation estimates are reflected in earnings in the period an estimate is revised.
Coal mines: We have asset retirement obligations for the final reclamation costs and environmental obligations for post-reclamation monitoring related to the Colowyo Mine and the New Horizon Mine. The New Horizon Mine is currently in post-reclamation monitoring. Two pits at the Colowyo Mine are in final reclamation with the other pit still being actively mined.
Generation: We have asset retirement obligations related to equipment, dams, ponds, wells and underground storage tanks at the generating stations.
Aggregate carrying amounts of asset retirement obligations and environmental reclamation obligations are as follows (dollars in thousands):
Nine Months Ended September 30, 2024
Obligations at beginning of period$217,201 
Liabilities incurred3,456 
Liabilities settled(2,628)
Accretion expense5,669 
Change in estimate12,634 
Total obligations at end of period$236,332 
Less current obligations at end of period(16,337)
Long-term obligations at end of period$219,995 
The New Horizon Mine environmental remediation liability balance is $67.3 million as of September 30, 2024. Of this amount, $36.8 million is recorded on a discounted basis, using a discount rate of 3.25 percent, with total estimated undiscounted future cash outflows of $57.9 million. Environmental obligation expense is included in other operating expenses on our consolidated statements of operations. During the three months ended September 30, 2024, we recognized a change in estimate related to the Colowyo Mine asset retirement obligation due to a change in the planned timing of full reclamation to 2025 and an updated cost estimate. We continue to evaluate the New Horizon Mine and Colowyo Mine post reclamation obligations and will make adjustments to these obligations as needed.
We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate fair value.
In May 2024, the Environmental Protection Agency ("EPA") published a final rule regarding groundwater monitoring, corrective action, closure, and post-closure care requirements for all coal combustion residuals management units under the Resource Conservation and Recovery Act. We are analyzing the final rule for possible impacts on our operations.
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NOTE 11 – OTHER DEFERRED CREDITS AND OTHER LIABILITIES
The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands):
September 30,
2024
December 31,
2023
Transmission easements$18,770 $17,862 
OATT deposits52,348 27,872 
Financial liabilities - reclamation11,337 16,895 
Customer deposits16,179 12,091 
Contract liabilities (unearned revenue) - noncurrent3,121 3,125 
Lease liabilities - noncurrent5,703 1,396 
Other6,618 4,884 
Total other deferred credits and other liabilities$114,076 $84,125 
In 2015, we renewed transmission right-of-way easements on tribal nation lands where certain of our electric transmission lines are located. $26.1 million will be paid by us for these easements from 2024 through the individual easement terms ending between 2035 and 2047. The present values for the remaining easement payments were $18.8 million as of September 30, 2024 and December 31, 2023 which are recorded as other deferred credits and other liabilities.
OATT deposits represent refundable transmission customer deposits related to interconnection and transmission requests from third parties. An OATT deposit is refundable as provided in our Open Access Transmission Tariff.
Financial liabilities - reclamation represent financial obligations that we have for our share of reclamation costs at jointly owned facilities in which we have undivided interests in.
A lease liability represents a lessee’s obligation to make lease payments over the lease term. The long-term portion of our lease liabilities are included in other deferred credits and other liabilities and the current portion of our lease liabilities are included in current liabilities. See Note 15 – Leases.
A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in contract liabilities (unearned revenue) until recognized in other operating revenues over the life of the agreement. We have received deposits from various parties and those that may still be required to be returned are a liability and these are reflected in customer deposits.
NOTE 12 – EMPLOYEE BENEFIT PLANS
Postretirement Benefits Other Than Pensions
We sponsor three medical plans for all non-bargaining unit employees under the age of 65. Two of the plans provide postretirement medical benefits to full-time non-bargaining unit employees and retirees who receive benefits under those plans, who have attained age 55, and who elect to participate. All three of these non-bargaining unit medical plans offer post employment medical benefits to employees on long-term disability. The plans were unfunded as of September 30, 2024, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles. As of June 30, 2021, the plans ceased to provide postretirement medical benefits for employees who retire after June 30, 2021.
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The postretirement medical benefit and post employment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and post employment obligations on our consolidated statements of financial position as follows (dollars in thousands):
Nine Months Ended September 30, 2024
Postretirement medical benefit obligation at beginning of period$924 
Interest cost43 
Benefit payments (net of contributions by participants)(270)
Postretirement medical benefit obligation at end of period$697 
Postemployment medical benefit obligation at end of period243 
Total postretirement and postemployment medical obligations at end of period$940 
The service cost component of our net periodic benefit cost, if any, is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations.
In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the postretirement medical benefit obligation.
The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligations are included in accumulated other comprehensive income as follows (dollars in thousands):
Nine Months Ended September 30, 2024
Amounts included in accumulated other comprehensive income at beginning of period$1,114 
Amortization of prior service credit into other income(661)
Amounts included in accumulated other comprehensive income at end of period$453 
Defined Benefit Plans
We participate in the NRECA Pension Restoration Plan and the NRECA Executive Benefit Restoration Plan, both of which are intended to provide a supplemental benefit to the defined benefit plan for an eligible group of highly compensated employees. Eligible employees include the Chief Executive Officer and any other employees that become eligible. All our executive employees with a hire date prior to May 1, 2021 participate in one of the following pension restoration plans: the NRECA Pension Restoration Plan or the NRECA Executive Benefit Restoration Plan. Eligibility is determined annually and is based on January 1 base salary that exceeds the limits of the defined benefit plan. Employees hired May 1, 2021 or later are not eligible for either plan.
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The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and post employment obligations on our consolidated statements of financial position as follows (dollars in thousands):
Nine Months Ended September 30, 2024
Executive benefit restoration obligation at beginning of period$10,158 
Service cost228 
Interest cost330 
Benefit payments(898)
Executive benefit restoration at end of period$9,818 
Fair value of plan assets at beginning of period$10,298 
Benefits paid(898)
Actual return on plan assets417 
Fair value of plan assets at end of period$9,817 
Net liability recognized at end of period$1 
The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. We have an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary.
In accordance with the accounting standard related to defined benefit pension plans, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the executive benefit restoration obligation.
The net unrecognized actuarial gains and losses related to the executive benefit restoration obligations are included in accumulated other comprehensive income as follows (dollars in thousands):
Nine Months Ended September 30, 2024
Accumulated other comprehensive loss at beginning of period$(1,639)
Amortization of prior service cost into other income729 
Accumulated other comprehensive loss at end of period$(910)

NOTE 13 – REVENUE
Revenue from Contracts with Customers
Our revenues are derived primarily from the sale of wholesale electric service to our Utility Members pursuant to long-term wholesale electric service contracts. Our contracts with our Utility Members extend through 2050.
Member electric sales
Revenues from wholesale electric power sales to our Utility Members are primarily from our Class A wholesale rate schedule filed with FERC. Our Class A rate schedule (A-40) was a stated rate and accepted by FERC on March 20, 2020. Our A-40 rate for electric power sales to our Utility Members remained in effect until July 31, 2024 and consisted of three billing components: an energy rate and two demand rates.
Our Class A rate schedule (A-41) for electric power sales to our Utility Members was accepted by FERC, effective August 1, 2024, subject to refund, and incorporated a new formulary rate, which can be adjusted annually based on the budgets approved by our Board, including an annual true-up mechanism. Our A-41 rate consists of eleven rate components, with three energy based and eight demand based. Our budget used to set our Utility Members' formula rate is set by our Board.
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Energy and demand have the same pattern of transfer to our Utility Members and are both measurements of the electric power provided to our Utility Members. Therefore, the provision of electric power to our Utility Members is one performance obligation. Prior to our Utility Members’ requirement for electric power, we do not have a contractual right to consideration as we are not obligated to provide electric power until the Utility Member requires each incremental unit of electric power. We transfer control of the electric power to our Utility Members over time and our Utility Members simultaneously receive and consume the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method, meter readings are taken at the end of each month for billing purposes, energy and demand are determined after the meter readings and Utility Members are invoiced based on the meter reading. Payments from our Utility Members are received in accordance with the wholesale electric service contracts’ terms, which is less than 30 days from the invoice date. Utility Member electric sales revenue is recorded as Utility Member electric sales on our consolidated statements of operations and Accounts receivable – Utility Members on our consolidated statements of financial position.
In addition to our Utility Member electric sales, we have non-member electric sales and other operating revenue which consist of several revenue streams. The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
Non-member electric sales:
Long-term contracts$35,481 $9,731 $86,669 $31,527 
Short-term contracts38,462 41,563 61,661 80,202 
Rate stabilization108,222 14,041 125,123 36,862 
Provision for rate refunds (210) 94 
Coal sales7,856 3,675 11,314 8,069 
Other29,263 11,943 69,453 40,093 
Total non-member electric sales and other operating revenue$219,284 $80,743 $354,220 $196,847 
Non-member electric sales
Revenues from wholesale electric power sales to non-members are primarily from long-term contracts and short-term market sales. Prior to our customers’ demand for energy, we do not have a contractual right to consideration as we are not obligated to provide energy until the customer demands each incremental unit of energy. We transfer control of the energy to our customer over time and our customer simultaneously receives and consumes the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method. Payments are received in accordance with the contract terms, which is less than 30 days after the invoice is received by the customer.
Rate Stabilization
Rate stabilization represents revenue recognition from withdrawal of former Utility Members from membership in us that was previously deferred in accordance with accounting requirements related to regulated operations. We recognized $125.1 million of deferred membership withdrawal income for the nine months ended September 30, 2024 compared to $36.9 million of deferred membership withdrawal for the nine months ended September 30, 2023. Of the total amount of deferred membership withdrawal income recognized during 2024, we recognized $76.4 million in September 2024 related to our rate stabilization measures to offset the expense recognition related to the $68.2 million write off of the J.M. Shafer Generating Station and Colowyo Coal acquisition costs/goodwill and $8.2 million in accelerated expenses related to the transition from mining to full reclamation at the Colowyo Mine in 2025. See Note 1 - Presentation of Financial Information and Note 2 - Accounting for Rate Regulation.
Coal sales
Coal sales revenue results from the sale of coal from the Colowyo Mine to third parties. We have an obligation to deliver coal and progress of completion toward our performance obligation is measured using the output method. Our performance obligation is completed as coal is delivered. We recognize coal sales revenue in other operating revenue on our consolidated statements of operations.
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Other operating revenue
Other operating revenue consists primarily of wheeling, transmission and lease revenue. Other operating revenue also includes revenue we receive from our Non-Utility Members. Wheeling revenue is earned when we charge other energy companies for transmitting electricity over our transmission lines (payments are received in accordance with the contract terms which is within 20 days of the date the invoice is received). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets in the Eastern Interconnection because of our membership in it (Southwest Power Pool collects the revenue from the customer and pays us for the scheduling, system control, dispatch transmission service, and the annual transmission revenue requirement). Each of these services or goods are provided over time and progress toward completion of our performance obligations are measured using the output method. Lease revenue is from lease agreements where we are the lessor for certain operational assets with third parties including a tolling agreement with a third party at our Knutson Generating Station. See Note 15 - Leases.
NOTE 14 – INCOME TAXES
We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in the consolidated financial statements. We adopted the normalization method January 1, 2020 pursuant to FERC regulation. Our subsidiaries not subject to FERC regulation continued to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payables that will be settled or received through future rate revenues.
Under ASC 740-270, we calculate an estimate of the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full fiscal year to income or loss (pretax income or loss excluding unusual or infrequently occurring discrete items) for the reporting period, after regulatory affect. Our consolidated statements of operations included no income tax expense or benefit for the nine months ended September 30, 2024 and an income tax expense of $67 thousand for the comparable period in 2023. We are continuing to evaluate the tax impacts of the contract termination payment received from United Power. Any current tax expense expected to be realized as a result of this contract termination payment, if any, will be recorded in the fourth quarter of 2024 when the amount of deferred revenue recognized will be known.
On August 16, 2022, the Inflation Reduction Act of 2022 (the "IRA") was enacted into law. The IRA enacted many provisions intended to mitigate climate change by providing various sources of funding and tax credit incentives for investments designed to reduce greenhouse gas emissions. These provisions do not impact our current consolidated financial statements but could affect future financial statements due to the impact of such investments. These provisions are subject to regulations and other guidance to be released by the U.S. Department of the Treasury, the U.S. Department of Agriculture and other governmental agencies over time. We are monitoring developments and evaluating opportunities to utilize these incentives. In September 2023, we submitted a Letter of Interest to apply for a funding award of low-cost loans and grants through the New Empowering Rural America ("New ERA") Program. The New ERA Program implements the $9.7 billion funded in the IRA. In October 2024, we received an award commitment letter from the USDA to fund $2.49 billion of our clean energy investments.
NOTE 15 – LEASES
Leasing Arrangements as Lessee
We determine if an arrangement is a lease upon commencement of the contract. If an arrangement is determined to be a long-term lease (greater than 12 months), we recognize a right-of-use asset and lease liability based on the present value of the future minimum lease payments over the lease term at the commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Our lease terms may also include options to extend or terminate the lease when it is reasonably certain that we will exercise those options. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Right-of-use assets are included in other deferred charges, the current portion of lease liabilities is included in accrued expenses and the long-term portion of lease liabilities is included in other deferred credits and other liabilities on our consolidated statements of financial position.
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We have elected to apply the short-term lease exception for contracts that have a lease term of twelve months or less and do not include an option to purchase the underlying asset. Therefore, we do not recognize a right-of-use asset or lease liability for such contracts. We recognize short-term lease payments as expense on a straight-line basis over the lease term. Variable lease payments that do not depend on an index or rate are recognized as expense.
Operating Leases
We have lease agreements as lessee for the right to use various facilities and operational assets. Rent expense for all short-term and long-term operating leases was $0.7 million for the three months ended September 30, 2024 and $0.6 million for the comparable period in 2023. Rent expense for all short-term and long-term operating leases was $1.9 million for the nine months ended September 30, 2024 and $1.8 million for the comparable period in 2023. Rent expense is included in various categories of operating expenses on our consolidated statements of operations based on the type and purpose of the lease.
Our consolidated statements of financial position include the following lease components (dollars in thousands):
September 30,
2024
December 31,
2023
Operating leases:
Operating lease right-of-use assets$13,106 $9,072 
Less: Accumulated amortization(2,903)(2,595)
Net operating lease right-of-use assets$10,203 $6,477 
Operating lease liabilities - current$(319)$(371)
Operating lease liabilities - noncurrent(5,678)(1,396)
Total operating lease liabilities$(5,997)$(1,767)
Finance leases:
Finance lease right-of-use assets$95 $ 
Less: Accumulated amortization(18) 
Net finance lease right-of-use assets$77 $ 
Finance lease liabilities - current$(47)$ 
Finance lease liabilities - noncurrent(25) 
Total finance lease liabilities$(72)$ 
Lease Term and Discount Rate:
Weighted-average remaining lease term (in years)
Operating leases32.77.0
Finance leases1.50.0
Weighted-average discount rate
Operating leases6.92 %4.68 %
Finance leases6.99
Future expected minimum lease commitments under operating leases are as follows (dollars in thousands):
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Operating LeasesFinance LeasesTotal
Year 1$654 $51 $705 
Year 2523 25 548 
Year 3535  535 
Year 4548  548 
Year 5391  391 
Thereafter12,320  12,320 
Total lease payments$14,971 $76 $15,047 
Less imputed interest(8,974)(4)(8,978)
Total$5,997 $72 $6,069 
Leasing Arrangements as Lessor
We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $6.1 million and $1.7 million for the three months ended September 30, 2024 and 2023 and $12.6 million and $5.1 million for the nine months ended September 30, 2024 and 2023, respectively, are included in other operating revenue on our consolidated statements of operations.
In May 2024, the conditions for the effectiveness of a tolling agreement with a third party were satisfied for our two 70 MW units at our Knutson Generating Station for all capacity and energy through the operation of both units. In September 2024, we entered into a tolling agreement with a third party for one of our two 70 MW units at our Limon Generating Station for all capacity and energy through the operation of that unit that will commence in January 2026. In substance these agreements were determined to be leases in accordance with the accounting standards for leases as the third party has the right to the economic benefits of the asset and controls the use of the asset by its contractual rights, including the ability to direct the timing of dispatch of energy.
The lease arrangement with the Springerville Partnership is not reflected in our lease right right-of-use asset or liability balances as the associated revenues and expenses are eliminated in consolidation. See Note 17 - Variable Interest Entities. However, as the non-controlling interest associated with this lease arrangement generates book-tax differences, a deferred tax asset and liability have been recorded.
NOTE 16 – FAIR VALUE
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal or in the most advantageous market when no principal market exists. The fair value measurement accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows:
Level 1 inputs are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities.
Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models, discounted cash flow models) for which all significant assumptions are observable in the market.
Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity.
In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to
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determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3.
Executive Benefit Restoration Plan Trust
We have an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. The trust consists of investments in equity and debt securities and are measured at fair value on a recurring basis. Changes in the fair value of investments in equity securities are recognized in earnings and changes in fair value of investments in debt securities classified as available-for-sale are recognized in other comprehensive income until realized. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands):
September 30, 2024December 31, 2023
CostEstimated
Fair Value
CostEstimated
Fair Value
Marketable securities$10,040 $9,817 $10,821 $10,298 
Marketable Securities
We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are measured at fair value on a recurring basis with changes in fair value recognized in earnings. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands):
September 30, 2024December 31, 2023
CostEstimated
Fair Value
CostEstimated
Fair Value
Marketable securities$553 $581 $576 $530 
Cash Equivalents
We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $249.0 million as of September 30, 2024 and $83.0 million as of December 31, 2023.
Debt
The fair values of long-term debt, excluding amounts reclassified from short-term debt, were estimated using discounted cash flow analyses based on our current incremental borrowing rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated inputs). The principal amounts and fair values of our debt are as follows (dollars in thousands):
September 30, 2024December 31, 2023
Principal
Amount
Estimated
Fair Value
Principal
Amount
Estimated
Fair Value
Total long-term debt$2,905,162 $2,642,121 $3,137,534 $2,909,301 
NOTE 17 – VARIABLE INTEREST ENTITIES
The following is a description of our financial interests in variable interest entities that we consider significant. This includes an entity for which we are determined to be the primary beneficiary and therefore consolidate.
Consolidated Variable Interest Entity
Springerville Partnership: We own a 51 percent equity interest, including the 1 percent general partner equity interest, in the Springerville Partnership, which is the 100 percent owner of Springerville Unit 3 Holding LLC (“Owner Lessor”). The Owner Lessor is the owner of the Springerville Unit 3. We, as general partner of the Springerville Partnership,
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have the full, exclusive and complete right, power and discretion to operate, manage and control the affairs of the Springerville Partnership and take certain actions necessary to maintain the Springerville Partnership in good standing without the consent of the limited partners. Additionally, the Owner Lessor has historically not demonstrated an ability to finance its activities without additional financial support. The financial support is provided by our remittance of lease payments in order to permit the Owner Lessor, the holder of the Springerville Unit 3 assets, to pay the debt obligations and equity returns of the Springerville Partnership. We have the primary risk (expense) exposure in operating the Springerville Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville Unit 3 and the decisions related to those expenditures including budgeting, financing and dispatch of power. Based on all these facts, it was determined that we are the primary beneficiary of the Owner Lessor. Therefore, the Springerville Partnership and Owner Lessor have been consolidated by us.
Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands):
September 30,
2024
December 31,
2023
Net electric plant$686,514 $703,859 
Noncontrolling interest130,453 134,269 
Long-term debt172,942 206,027 
Accrued interest1,999 5,968 
Our consolidated statements of operations include the following Springerville Partnership expenses for the three and nine months ended September 30, 2024 and 2023 (dollars in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
Depreciation, amortization and depletion$8,276 $4,535 $17,345 $13,603 
Interest2,849 3,397 8,734 10,465 
The revenue associated with the Springerville Partnership lease has been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages. The net income or loss attributable to the 49 percent non-controlling equity interest in the Springerville Partnership is reflected on our consolidated statements of operations.
NOTE 18 – LEGAL
Other than as disclosed below, we do not expect any litigation or proceeding pending or threatened against us to have a potential material effect on our financial condition, results of operations or cash flows.
CTP Proceeding: Pursuant to our Bylaws, a Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Member shall be permitted to withdraw until it has met all their contractual obligations to us. On September 1, 2021, we filed with FERC a modified contract termination payment methodology tariff as Rate Schedule 281 that provides a process should a Utility Member elect to withdraw from membership in us and terminate their wholesale electric service contract. The tariff process includes requirements for a two-year notice and the payment to us of a contract termination payment. On October 29, 2021, FERC accepted our modified contract termination payment methodology, effective November 1, 2021, subject to refund. FERC set the matter for hearing and instituted a concurrent Federal Power Act ("FPA") section 206 proceeding to determine the justness and reasonableness of our modified methodology.
On April 29, 2022, both United Power and Northwest Rural Public Power District ("NRPPD") provided us notices to withdraw from membership in us, with a May 1, 2024 withdrawal effective date.
On December 19, 2023, FERC issued an order adopting a modified balance sheet approach for the contract termination payment methodology ("FERC December 19 Order"). On January 18, 2024, we, United Power, and others filed requests for rehearing with FERC of the FERC December 19 Order. Our request for rehearing included FERC's rejection of our lost revenue approach and also certain clarifications. On February 20, 2024, FERC issued a notice stating the parties' requests for rehearing were denied by operation of law, but FERC stated it will address the merits of the requests in a subsequent order. On March 28, 2024, we filed a petition for review of the FERC December 19 Order with the United States Court of Appeals for the Tenth
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Circuit ("10th Circuit Court of Appeals"), Case No. 24-9516. On April 8, 2024, United Power filed a petition for review of the FERC December 19 Order with the United States Court of Appeals for the District of Columbia Circuit ("DC Circuit Court of Appeals"), Case No. 24-1081. United Power, Mountain Parks Electric, Inc. ("MPEI"), NRPPD, Basin Electric Power Cooperative ("Basin"), and La Plata Electric Association, Inc. ("LPEA") have filed notices of interventions in our petition for review with the 10th Circuit Court of Appeals. On May 14, 2024, the DC Circuit Court of Appeals granted a motion to transfer United Power’s petition to the 10th Circuit Court of Appeals, Case No. 24-9532.
On May 23, 2024, FERC issued a substantive order on rehearing, which modifies the discussion in, but sustains the results of, the FERC December 19 Order (“May 23 Order”). On May 31, 2024, we filed a petition for review of the May 23 Order, Case No. 24-9538, with the 10th Circuit Court of Appeals. On June 3, 2024, the 10th Circuit Court of Appeals issued an order partially consolidating Case No. 24-9538 with Case Nos. 24-9516 and 24-9532 for purposes of briefing. We and United Power filed opening briefs with the 10th Circuit Court of Appeals on October 7, 2024. Basin filed their opening brief in support of us and certain other intervening petitioners filed their combined opening brief in support of United Power on October 28, 2024.
On January 25, 2024, we filed a revised Rate Schedule 281 with FERC with the contract termination methodology based upon the FERC December 19 Order. On March 29, 2024, FERC issued an order accepting our revised Rate Schedule 281, subject to further compliance filing, and established hearing and settlement judge procedures related to our sleeving administrative fee methodology set forth in our revised Rate Schedule 281. On April 12, 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's March 2024 order. On June 28, 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's May 23 Order. FERC has not issued an order on our April 2024 or June 2024 revised Rate Schedule 281 so our January 2024 Rate Schedule 281 is currently on-file with FERC.
On May 1, 2024, United Power withdrew from membership in us and terminated their wholesale electric service contract with us pursuant to Rate Schedule 281 on-file with FERC and a Membership Withdrawal Agreement with United Power. United Power’s contract termination payment amount was $709.4 million. United Power paid us an exit fee in cash of $627.2 million, after a regulatory liabilities credit and United Power relinquishing their right to any patronage capital in us resulting in a discounted patronage capital credit of $82.2 million. Such amounts remain subject to true-up in accordance with Rate Schedule 281 and United Power's Membership Withdrawal Agreement. As provided in the Membership Withdrawal Agreement, United Power's exit fee is also subject to true-up in the event Rate Schedule 281 and the amount paid by United Power are modified pursuant to a subsequent final and non-appealable FERC order, including resolution of the petitions for review filed by us and United Power. It is not possible to predict the outcome of this matter or whether we will be required to refund any amounts to United Power or if United Power will be required to pay us any additional amounts.
NRPPD did not comply with Rate Schedule 281 on-file with FERC and made no contract termination payment to us. NRPPD’s wholesale electric service contract with us remains in effect and NRPPD remains a Class A member of us. NRPPD’s April 29, 2022 notice of intent to withdraw is deemed null and void. NRPPD is disputing our position that their wholesale electric service contract with us remains in effect and NRPPD remains a Class A member of us. It is not possible to predict the outcome of the proceedings related to NRPPD's status as a Class A member or their position that it has terminated their wholesale electric service contracts with us and whether we will suffer any liability or loss from the proceedings.
LPEA's La Plata County District Court Complaint. On November 10, 2023, LPEA filed a complaint with the La Plata County District Court, Case No. 2023CV30148, against us. The complaint alleges, among other things, that we have breached our Bylaws and our wholesale electric service contract with LPEA by failing to provide equitable terms and conditions for LPEA to withdraw from us and by violating the implied covenant of good faith and fair dealing. LPEA seeks a declaratory order that we have materially breached our Bylaws and our wholesale electric service contract and that LPEA is relieved from any further obligation to perform under those agreements, or in the alternative, damages from us for such alleged breach. On January 10, 2024, we filed a motion to dismiss stating that LPEA's claims are barred by federal preemption and the statute of limitations. On July 18, 2024, the court denied our motion to dismiss, ruling that the case was not preempted by FERC's jurisdiction and should not be dismissed for violating the statute of limitations. On August 1, 2024, we filed our answer denying all of the allegations in LPEA's complaint and that LPEA is entitled to any relief. It is not possible to predict the outcome of this matter, whether we will incur any liability in connection with this matter, and in the event of liability, if any, the amount or type of damages, equitable relief or other legal relief that could be awarded or granted.
NRPPD Complaint: On March 25, 2024, NRPPD filed a FPA section 206 proceeding with FERC, Docket No. EL24-93, against us and Basin seeking FERC to exercise primary jurisdiction over the interpretation of the FERC December 19 Order and our Amended and Restated Wholesale Power Contract for the Eastern Interconnection with Basin ("Basin Eastern WPC"). In particular, NRPPD requests that FERC hold that NRPPD’s withdrawal from us is permissible under the Basin Eastern WPC and that NRPPD’s contract termination payment calculation is the appropriate contract termination payment. NRPPD further seeks refunds from us because Basin has allegedly overcharged us and thus NRPPD for sales of power and
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energy under the Basin Eastern WPC for Basin’s financial losses caused by Basin’s Urea facility. On May 8, 2024, we and Basin separately filed answers to NRPPD's complaint. Both us and Basin requested FERC to deny NRPPD's complaint. We also requested to the extent FERC determines that NRPPD's withdrawal is permissible under the Basin Eastern WPC that we can be permitted to allocate the withdrawing member its portion of costs related to the Basin Eastern WPC pursuant to our Rate Schedule 281 to prevent the cost of the obligation from shifting to remaining members. On May 28, 2024, NRPPD filed a response to our and Basin's answers and again asserted that their withdrawal from us is permissible under the Basin Eastern WPC and if, prohibited, the Basin Eastern WPC be held not just and reasonable and NRPPD be permitted to withdraw from us. It is not possible to predict the outcome of this matter or whether we will incur any liability or loss in connection with this matter.
Energy Sales - Soft-Cap: In August 2020, we made certain energy sales to third parties in excess of the soft-cap price for short-term, spot market sales of $1,000 per megawatt hour established by the Western Electricity Coordinating Council. On October 7, 2020, we filed a report with FERC justifying the sales above the soft-cap and we did not recognize the revenue for the energy sales in excess of the soft-cap, Docket No. EL21-65-000. Based upon additional guidance from FERC, we filed a supplemental report on July 19, 2021. On May 20, 2022, FERC issued an order directing us to refund only certain amounts of the energy sales revenue in excess of the soft-cap. Based upon the FERC order, in the second quarter of 2022, we recognized approximately $2.9 million in excess of the soft-cap and refunded $0.4 million to a third party. On July 22, 2022, the California Public Utilities Commission filed a petition for review with the DC Circuit Court of Appeals of FERC’s May 20, 2022 order, Case No. 22-1169. On August 18, 2022, we filed a motion to intervene with the DC Circuit Court of Appeals and an order granting our motion was issued on September 6, 2022. On January 24, 2023, the parties to the proceeding filed a motion with the court to consolidate this proceeding with other related proceedings with the DC Circuit Court of Appeals and proposed a procedural schedule with final briefings due in October 2023. On March 6, 2023, the DC Circuit Court of Appeals granted the motion to consolidate the proceedings. On October 31, 2023, the final briefs were filed in this consolidated proceeding. On July 9, 2024, the DC Circuit Court of Appeals issued an order vacating FERC's order and remanding the case back to FERC to conduct a Mobile-Sierra analysis. It is not possible to predict the outcome of this matter or whether we will be required to refund any additional amounts to third parties.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis. We were formed by our Utility Members for the purpose of providing wholesale power and transmission services to our Utility Members (which are distribution electric cooperatives and public power districts) for their resale of the power to their retail consumers. Our Utility Members serve large portions of Colorado, Nebraska, New Mexico and Wyoming. We also sell a portion of our generated electric power to other utilities in our regions pursuant to long-term contracts and short-term sale arrangements. Our Utility Members provide retail electric service to suburban and rural residences, farms and ranches, cities, towns and communities, as well as large and small businesses and industries.
We are currently owned entirely by our forty-four Members. We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. For our forty-one Class A members, we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members, and therefore all our Utility Members are currently Class A members. We have three Non-Utility Members. Thirty-seven of our Utility Members are not-for-profit, electric distribution cooperative associations. Four Utility Members are public power districts, which are political subdivisions of the State of Nebraska. We became regulated as a public utility under Part II of the FPA on September 3, 2019 when we admitted a Non-Utility Member, MIECO, Inc. (a non-governmental/non-electric cooperative entity), as a new Member/owner.
We supply and transmit our Utility Members’ electric power requirements through a portfolio of resources, including generation and transmission facilities, long term purchase contracts and short-term energy purchases. We own, lease, have undivided percentage interests in, or long-term purchase contracts with respect to various generating facilities. Our diverse generation portfolio provides us with maximum available power of 4,523 MWs, of which approximately 1,566 MWs comes from renewables.
We sold 13.4 million MWhs for the nine months ended September 30, 2024, a decrease of 2.4 percent as compared to the nine months ended September 30, 2023, of which 87.2 percent was to Utility Members. Total revenue from electric sales was $1.0 billion for the nine months ended September 30, 2024 of which 85.3 percent was from Utility Member sales. Our results for the nine months ended September 30, 2024 were primarily impacted by higher non-member electric sales and lower natural gas prices.
Utility Member electric sales decreased $60.3 million, or 6.5 percent, primarily due to a decrease of 810,472 MWhs sold, or 6.5 percent, for the nine months ended September 30, 2024 compared to the same period in 2023. The impact of United Power’s withdrawal on May 1, 2024 was offset by increased sales to our remaining Utility Members sales due to load growth and other factors.
Non-member electric sales increased $36.6 million, or 32.8 percent, primarily due to higher long-term sales (in MWhs), offset by decreased short-term market sales and lower average prices.
Fuel expense decreased $30.1 million, or 15.2 percent, primarily due to a decrease in generation at both our coal and gas-fired facilities, as well as lower market prices.
Wholesale Electric Service Contracts
Our Bylaws require each Utility Member, unless otherwise specified in a written agreement or the terms of the Bylaws, to purchase from us electric power and energy as provided in the Utility Member's contract with us. This contract is the wholesale electric service contract with each Utility Member, which is an all-requirements contract. Each wholesale electric service contract obligates us to sell and deliver to the Utility Member, and obligates the Utility Member to purchase and receive, at least 95 percent of its electric power requirements from us. Our wholesale electric service contracts with our 41 Utility Members extend through 2050. We had a wholesale electric service contract with United Power that extended through 2050. United Power withdrew from membership in us on May 1, 2024 and their wholesale electric service contract with us was terminated. Each Utility Member may elect to provide up to 5 percent of its electric power requirements from distributed or renewable generation owned or controlled by the Utility Member. As of September 30, 2024, 21 Utility Members have enrolled in this program with capacity totaling approximately 94 MWs of which 88 MWs are in operation.
We have presented to our Utility Members and received feedback on alternatives for an increased amount of self-supply in addition to the 5 percent self-supply provision of our wholesale electric services contracts. The alternative that emerged through our collaboration with our Utility Members is known as the Bring Your Own Resource Program, which is
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designed to provide our Utility Members with the flexibility to build, own or contract for power supply projects. Under the Bring Your Own Resource Program, Utility Members interested in participating in the program will propose projects that they will own or control and that do not exceed 40 percent of their 2022 peak load during our peak period and which projects will not have an adverse impact on our reliability, overall system costs or compliance with environmental objectives. In June 2024, we filed with FERC a tariff describing the parameters of the Bring Your Own Resource Program. In August 2024, FERC accepted our tariff and the inaugural Bring Your Own Resource Program cycle was initiated in the third quarter of 2024 and is expected to conclude in the third quarter of 2025. If a Utility Member-proposed resource is accepted following the program evaluation process, a Utility Member will enter into an agreement enabling us to purchase the output of the Bring Your Own Resource project and that output will be deemed to serve the Utility Member’s load.
Member Withdrawals and Relationship with Members
Pursuant to our Bylaws, a Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Member shall be permitted to withdraw until it has met all its contractual obligations to us. In September 2021, we filed with FERC a modified contract termination payment methodology tariff as Rate Schedule 281 that provides a process should a Utility Member elect to withdraw from membership in us and terminate their wholesale electric service contract with us. The tariff process includes requirements for a two-year notice and the payment to us of a contract termination payment. In October 2021, FERC accepted our modified contract termination payment methodology, effective November 1, 2021, subject to refund. FERC set the matter for hearing and instituted a concurrent FPA section 206 proceeding to determine the justness and reasonableness of our modified methodology.
In December 2023, FERC issued an order adopting a modified balance sheet approach for the contract termination payment methodology. In January 2024, we filed a revised Rate Schedule 281 with FERC with the contract termination methodology based upon FERC's order. The revised Rate Schedule 281 based upon FERC's adopted balance sheet approach uses our FERC financials and distinguishes between Utility Members served on the Western and Eastern Interconnection. In March 2024, FERC issued an order accepting our revised Rate Schedule 281, subject to further compliance filing, and established hearing and settlement judge procedures related to our sleeving administrative fee methodology set forth in our revised Rate Schedule 281. In April 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's March 2024 order. In June 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's May 2024 order on rehearing. FERC has not issued an order on our April 2024 or June 2024 revised Rate Schedule 281 so our January 2024 Rate Schedule 281 is currently on-file with FERC. For further information on the methodology see “Item 1 – BUSINESS – MEMBERS - Contract Termination Payment and Relationship with Members” in our annual report on Form 10-K for the year ended December 31, 2023. See also Note 18 to the Unaudited Consolidated Financial Statements in Item 1 for further information.
On April 29, 2022, both United Power and NRPPD provided us notices to withdraw from membership in us, with a May 1, 2024 withdrawal effective date. In January 2023, MPEI provided us a notice to withdraw from membership in us, with a February 1, 2025 withdrawal effective date. In March 2024, LPEA provided us a notice to withdraw from membership in us, with an April 1, 2026 withdrawal effective date.
On May 1, 2024, United Power withdrew from membership in us and terminated their wholesale electric service contract with us pursuant to Rate Schedule 281 on-file with FERC and a Membership Withdrawal Agreement with United Power. United Power’s contract termination payment amount was $709.4 million. United Power paid us an exit fee in cash of $627.2 million, after a regulatory liabilities credit and United Power relinquishing their right to any patronage capital in us resulting in a discounted patronage capital credit of $82.2 million. Such amounts remain subject to true up in accordance with Rate Schedule 281 and United Power's Membership Withdrawal Agreement. Our Board deferred as a regulatory liability $530.1 million of United Power's $709.4 million contract termination payment amount. The remaining $179.3 million was related to a transmission credit for the portion of transmission debt allocated to United Power and required to be deferred pursuant to FERC's December 2023 order and Rate Schedule 281.
NRPPD did not comply with the Rate Schedule 281 on-file with FERC and made no contract termination payment to us. NRPPD’s wholesale electric service contract with us remains in effect and NRPPD remains a Class A member of us. NRPPD’s April 29, 2022 notice of intent to withdraw is deemed null and void. Contrary to FERC’s March 2024 order on our revised Rate Schedule 281 compliance filing, NRPPD has asserted there is no FERC-accepted Rate Schedule 281 on file with FERC and no contract termination payment is payable by NRPPD. Although NRPPD is disputing our position that their wholesale electric service contract with us remains in effect and NRPPD remains a Class A member of us, NRPPD is paying us for the electric power and energy we have provided to NRPPD.
In October 2024, we entered into a Membership Withdrawal Agreement with MPEI that was filed with FERC for acceptance. The Withdrawal Agreement describes the practical action items and related rights and obligations of the parties
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involved with effectuating the withdrawal of MPEI from membership in us and termination of MPEI's wholesale electric service contract on February 1, 2025. MPEI’s contract termination payment based upon our April 2024 revised Rate Schedule 281 is $77.9 million prior to any adjustments for discounted patronage capital, regulatory liabilities credit or MPEI's pro rata share of our power purchase obligations in the Western Interconnection. MPEI's estimated final payment amount stated in the Membership Withdrawal Agreement based upon our April 2024 revised Rate Schedule 281 after adjusting for MPEI's discounted patronage, regulatory liabilities credit, and the parties agreed to MPEI's share of our power purchase obligations in the Western Interconnection is $71.4 million. We and MPEI also entered a purchase and sales contract to sell MPEI certain assets for $5.9 million that is also expected to close on February 1, 2025, subject to receipt of COPUC approval.
LPEA’s estimated contract termination payments based upon our April 2024 revised Rate Schedule 281 is $209 million prior to any adjustment related to the withdrawal of MPEI, discounted patronage capital or regulatory liabilities credit, if applicable. The estimated contract termination payment for LPEA does not include their pro rata share of our power purchase obligations in the Western Interconnection. MPEI and LPEA comprised 7.5 percent of our Utility Member revenue and 5.3 percent of our operating revenue for the nine months ended September 30, 2024.
The contract termination payments for United Power, MPEI, and LPEA are subject to review and modification through proceedings currently pending with FERC and petitions for review filed in the federal courts. See Note 18 to the Unaudited Consolidated Financial Statements in Item 1 for further information.
Although there is no certainty that MPEI and LPEA will pay their respective contract termination payment required upon withdrawal and withdraw as they have asserted, if these Utility Members pay and withdraw, it will reduce our Utility Members' electric sales revenue and the amount of energy sold to our Utility Members. We expect the receipt of the contract termination payments from United Power, MPEI, and LPEA to assist in mitigating the impacts of decreased Utility Members electric sales revenue. We expect to defer some or all of the contract termination payments received as a regulatory liability and recognize as revenue in future period or periods to offset the revenue otherwise recoverable from Utility Members.
In addition, as part of mitigating the impacts, we expect our non-member electric sales revenue and the amount of energy sold to non-members to increase significantly. In anticipation of Utility Member withdrawals, we have entered into multiple power sales contracts with third parties for up to 410 MWs, a tolling agreement for our two 70 MW units at the Knutson Generating Station, and a tolling agreement for one of our two 70 MW units at the Limon Generating Station for the sale of capacity and energy. Phase I of our 2023 ERP also assumed United Power and MPEI will withdraw resulting in a decreased need for additional resources and costs as we transition to a cleaner energy portfolio and reduce our greenhouse gas emissions. However, there is no certainty that our mitigation steps or the contract termination payments will mitigate the full amount of the loss of Utility Member electric sales revenue. See also “Item 1 – BUSINESS – MEMBERS - Contract Termination Payment and Relationship with Members” and "RISK FACTORS - Members and Regulatory Risks" in our annual report on Form 10-K for the year ended December 31, 2023.
In November 2023, LPEA filed a complaint for declaratory judgement and damages against us alleging, among other things, that we have breached our Bylaws and our wholesale electric service contract with LPEA. In January 2024, we filed a motion to dismiss stating that LPEA's claims are barred by federal preemption and the statute of limitations. In July 2024, the court denied our motion to dismiss. In August 2024, we filed an answer denying all of LPEA's claims. See Note 18 to the Unaudited Consolidated Financial Statements in Item 1 for further information.
Responsible Energy Plan and Colorado Electric Resource Plan and New Era Program
Responsible Energy Plan
In January 2020, we released our energy transition plan known as our Responsible Energy Plan. With our Responsible Energy Plan, we are implementing a clean energy transition while being responsible to our employees, Members, communities, and environment. The plan was developed with input from our Board, our Utility Members and external stakeholders. Our plan is dynamic and will change as Utility Members' needs change, new technologies become available and market conditions evolve. We and our Utility Members have made great strides implementing the plan. Some of the highlights of the Responsible Energy Plan include:
eliminating all emissions from our coal-fired generating facilities in Colorado and New Mexico by 2030.
by 2025, 50 percent of the electricity our Utility Members use is expected to come from clean energy.
more local renewables for Utility Members through contract flexibility.
promoting participation in a regional transmission organization.
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expanding electric vehicle infrastructure and beneficial electrification.
For further information regarding our Responsible Energy Plan, see “Item 1 – BUSINESS — MEMBERS – Responsible Energy Plan” in our annual report on Form 10-K for the year ended December 31, 2023.
Colorado Electric Resource Plan
In December 2023, we filed Phase I of our 2023 ERP with the COPUC, which contained our preferred plan and submitted a filing in April 2024 affirming the preferred plan. Our preferred plan is the IRA scenario, which brings online 1,540 MWs of new resources during the resource acquisition period of 2026-2031, if we are awarded federal funding to support generation additions and provide stranded asset relief under the New ERA Program funding opportunity. Our preferred plan enables us to utilize direct pay of federal tax benefits for renewable and storage resources by increasing our owned resources. Our preferred plan retires Craig Generating Station Unit 3 by January 1, 2028 and, if we receive New ERA Program funding and reach agreements with the applicable parties, our preferred plan retires Springerville Unit 3 by September 15, 2031. These shifts in our generation portfolio included in our preferred plan over the coming years are expected to result in an 89 percent greenhouse gas emissions reduction for our wholesale electricity sales in Colorado in 2030, with respect to a verified 2005 baseline. This emissions reduction exceeds the emissions reduction target of 80 percent in 2030 required by Colorado law.
In June 2024, we filed an unopposed executed comprehensive settlement agreement for our Phase I of our 2023 ERP with the COPUC supporting its approval subject to the terms of the settlement, including the above referenced retirements of our generating facilities and retirement dates. The settlement resolves all issues raised by intervening parties for Phase I of our 2023 ERP and provides for updates related to the scope of Phase II procurement of our 2023 ERP, bid evaluation and portfolio modeling, and adds a demand response target for our Colorado peak load in 2030 of 5.5 percent. The settlement agreement provides for us to provide community assistance for northwest Colorado, which is the location of Craig Generating Station. Community assistance includes $22 million in direct total benefit to the northwest Colorado community between 2026 and 2029, with other potential investments providing $48 million in additional benefit to such community between 2028 and 2038. In August 2024, the administrative law judge for the COPUC recommended approval of the settlement agreement and the approval became effective in September 2024. For Phase II of our 2023 ERP, during our resource procurement process, we issued three requests for proposals in September 2024 seeking bids for new dispatchable, renewable, and storage resources for the resource acquisition period of 2026-2031. Bids were received in October 2024 and we expect to file in the first part of 2025 our Phase II implementation report of our 2023 ERP identifying our preferred portfolio for resource acquisitions for the 2026-2031 period. For our dispatchable request for proposal, for any bid for a new natural gas-fired generating facility to be owned by us it must be sited in Moffat County, Colorado. Other gas facility and geothermal bids under a tolling or power purchase arrangement have more geographic flexibility. For further information regarding Phase I of our 2023 ERP, see “Item 1 – BUSINESS — POWER SUPPLY RESOURCES – Resource Planning” in our annual report on Form 10-K for the year ended December 31, 2023.
New ERA Program
In September 2023, we submitted a Letter of Interest to apply for a funding award of low-cost loans and grants through the New ERA Program, a $9.7 billion program that is funded by the Inflation Reduction Act of 2022. Our portfolio proposed in our Letter of Interest was the result of resource and financial modeling performed in connection with our preferred IRA scenario as part of Phase I of our 2023 ERP. In March 2024, we received an Invitation to Proceed from the USDA to complete the New ERA Program Application, and in June 2024, we submitted our Application. In October 2024, we received an award commitment letter from USDA to fund $2.49 billion of our clean energy investments.
Our New ERA award supports financing for 1,280 MWs of energy from solar, wind, and wind/storage hybrid projects, more than 100 MWs of stand-alone energy storage projects, and retirement of 1,110 MWs for coal-fired generating facilities, which lessens the financial burden of stranded assets. The New ERA award will support the retirement of Springerville Unit 3, Craig Generating Station Units 2 and 3, and the already retired Escalante Generation Station. The award will also support two future energy storage projects owned by us, three of our existing renewable power purchase agreements, seven future renewable power purchase agreements, and two future wind/hybrid power purchase agreements. The release of the funding from the USDA is subject to satisfaction of certain conditions, including execution of a loan/grant agreement and applicable security agreement, development and/or implementation of a Community Benefits Plan where applicable and fulfillment of program Community Benefits Plan requirements, environmental approvals dependent on the type of project, and submittal of certain information, documents and certifications dependent on the type of project.
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Solar Projects Construction
In April 2024, we closed on the acquisition of the 145 MW Axial Basin Solar project being developed in northwestern Colorado located near the Colowyo Mine and issued a notice to an engineering, procurement and construction contractor to proceed with construction. Construction at Axial Basin continues to progress with access roads completed, cable trenching nearing completion, and racking and module installation in progress. All the Axial Basin solar modules have been either received on site, or placed in storage.
In May 2024, we closed on the acquisition of the 110 MW Dolores Canyon Solar project being developed in southwestern Colorado and issued a notice to an engineering, procurement and construction contractor to proceed with construction. Construction at Dolores Canyon continues to progress with the power station transformer foundations complete, the access roads and directional bores nearing completion and all the solar modules have been placed in storage.
Both projects are expected to achieve commercial operation in the second half of 2025 . We also expect to utilize direct pay of federal tax benefits as provided in the Inflation Reduction Act of 2022 for both projects.
Colowyo Mine Transition
In September 2024, our Board approved a 2025 budget reflecting a decision to transition from mining to full reclamation at Colowyo Coal's Colowyo Mine in the latter part of 2025. During the third quarter of 2024, we expensed $33.2 million in write-offs of acquisition costs/goodwill and pre-paid royalties related to the Colowyo Mine, and we accelerated approximately $7.4 million in depreciation and amortization related to asset retirement obligations, development costs and depletion of coal reserves. In addition, we anticipate approximately $3.0 million to $5.0 million of obsolete inventory to be recorded in the fourth quarter of 2024. Accelerated depreciation and amortization will continue in the fourth quarter of 2024 and through the latter part of 2025 in the approximate amounts of $22.2 million and $72.6 million, respectively. We expect to recognize deferred membership withdrawal income in an amount equal to such expenses resulting in no expected impact to our Utility Member's wholesale rate.
Critical Accounting Policies
The preparation of our financial statements in conformity with GAAP requires that our management make estimates and assumptions that affect the amounts reported in our consolidated financial statements. We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year. As of September 30, 2024, there were no material changes in our critical accounting policies as disclosed in our annual report on Form 10-K for the year ended December 31, 2023.
Factors Affecting Results
Master Indenture
As of September 30, 2024, we had approximately $2.7 billion of secured indebtedness outstanding under our Master Indenture. Substantially all of our tangible assets and certain of our intangible assets are pledged as collateral under our Master Indenture. Our Master Indenture requires us to establish rates annually that are reasonably expected to achieve a DSR of at least 1.10 on an annual basis and permits us to incur additional secured obligations as long as after giving effect to the additional secured obligation, we will continue to meet the DSR requirement on both a historical and pro forma basis. Our Master Indenture also requires us to maintain an ECR of at least 18 percent at the end of each fiscal year. Pursuant to our Master Indenture, DSR and ECR are calculated based on unconsolidated Tri-State financials and calculated in accordance with the system of accounts proscribed by FERC.
Margins and Patronage Capital
We operate on a cooperative basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to meet certain financial requirements and to establish reasonable reserves. Revenues in excess of current period costs in any year are designated as net margins in our consolidated statements of operations. Net margins are treated as advances of capital by our Members and are allocated to our Utility Members on the basis of revenue from electricity purchases from us and to our Non-Utility Members as provided in their respective membership agreement.
Our Board Policy for Financial Goals and Capital Credits, approved and subject to change or waiver by our Board, sets guidelines to achieve margins and retain patronage capital sufficient to maintain a sound financial position and to allow for the orderly retirement of capital credits allocated to our Members. On a periodic basis, our Board will determine whether to retire
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any patronage capital, and in what amounts, to our Members. As of September 30, 2024, we have retired approximately $605.8 million of patronage capital to our Members.

Pursuant to our Board Policy for Financial Goals and Capital Credits, we have historically set rates to achieve a DSR and ECR in excess of the requirements under our Master Indenture in order to mitigate the risk of potential negative variances between budgeted margins and actual margins. Our Board Policy for Financial Goals and Capital Credits, approved in 2023 in connection with our Board’s approval of a revised Class A rate schedule that uses a formula rate, includes three financial ratio goals for which we will set rates based upon an annual budget and true-up from the actual results of the previous fiscal year. The three financial goals are: (i) a minimum DSR of at least 1.15, (ii) a minimum ECR of at least 20 percent, and (iii) a minimum net margin attributable to us in each fiscal year of at least $20 million.
Rates and Regulation
On September 3, 2019, we became FERC jurisdictional for our Utility Members' rates, transmission service, and our market based rates. In December 2019, we filed with FERC our tariff filings, including our stated rate cost of service filing, market-based rate authorization, and transmission OATT. In March 2020, FERC issued orders generally accepting our tariff filings, subject to refund for sales after March 26, 2020. On August 2, 2021, FERC approved our settlement agreement related to our Utility Members' stated rate that provides for us to implement a two-stage, graduated reduction in the charges making up our A-40 rate of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from then current rates) on March 1, 2022 until July 31, 2024.
In May 2024, we filed with FERC a request to adopt a new Class A wholesale rate schedule (A-41) for electric power sales to our Utility Members. The filing included a 6.4 percent increase in our average wholesale rate. The wholesale rate maintains our postage stamp rate, with the same rate components for all our Utility Members, and incorporated a new formulary rate, which can be adjusted annually based on the budgets approved by our Board, including an annual true-up mechanism. In July 2024, FERC issued an order accepting our A-41 wholesale rate schedule, effective August 1, 2024, subject to refund. FERC further set our rate filing for settlement and hearing procedures and confirmed our accounting treatment, including amortization, and creation of regulatory assets for Escalante Generating Station, Rifle Generating Station, Craig Generating Station Units 2 and 3, and the New Horizon Mine environmental obligation. However, FERC did not authorize us to recover the regulatory assets that represent "acquisition costs/goodwill" for J.M. Shafer Generating Station and Colowyo Coal. These costs were on our books prior to us becoming subject to FERC's jurisdiction. FERC stated in its order accepting our A-41 rate schedule that we did not request express authorization to recover acquisition costs including goodwill in our rates. We wrote off the J.M. Shafer Generating Station and Colowyo "acquisition costs/goodwill" in September 2024 which resulted in recognition of expense of $68.2 million. We recognized deferred membership withdrawal income in September 2024 as part of our rate stabilization measures, therefore, the write off of the J.M Shafer Generating Station and Colowyo acquisition costs/goodwill resulted in no impact to our Utility Members' wholesale rate. For further information, see “Item 1 – BUSINESS — RATE REGULATION” in our annual report on Form 10-K for the year ended December 31, 2023.
Our electric sales revenues are derived from wholesale electric service sales to our Utility Members and non-member purchasers. Revenues from wholesale electric power sales to our non-member purchasers is primarily pursuant to our market-based rate authority.
Revenues from electric power sales to our Utility Members are primarily from our Class A wholesale rate schedule filed with FERC. Our Class A rate schedule (A-41) for electric power sales to our Utility Members consist of eleven rate components, with three energy based and eight demand based. Our budget used to set our Utility Members' formula rate is set by our Board, consistent with the provision of reliable cost-based supply of electricity over the long term to our Utility Members. Energy is the physical electricity delivered to our Utility Members. The energy-based rates are billed based upon a price per kWh of physical energy delivered and the demand-based rates are billed based on the Utility Member’s highest thirty-minute integrated total demand measured in each monthly billing period during our peak period, Monday through Saturday, with the exception of six holidays.
In September 2024, our Board approved our 2025 budget with the wholesale rate to our Utility Members unchanged through 2025.
Our Board may, from time to time, subject to FERC approval, create new regulatory assets or liabilities or modify the expected recovery period through rates of existing regulatory assets or liabilities.
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Tax Status
We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in the consolidated financial statements. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues.
Results of Operations
General
Our electric sales revenues are derived from wholesale electric service sales to our Utility Members and non-member purchasers. See “Factors Affecting Results – Rates and Regulation” for a description of our energy and demand rates to our Utility Members. Long-term contract sales to non-members generally include energy and demand components. Short-term sales to non-members are sold at market prices after consideration of incremental production costs. Demand billings to non-members are typically billed per kilowatt of capacity reserved or committed to that customer.
Weather has a significant effect on the usage of electricity by impacting both the electricity used per hour and the total peak demand for electricity. Consequently, weather has a significant impact on our revenues. Relatively higher summer or lower winter temperatures tend to increase the usage of electricity for heating, air conditioning and irrigation. Mild weather generally reduces the usage of electricity because heating, air conditioning and irrigation systems are operated less frequently. The amount of precipitation during the growing season (generally May through September) also impacts irrigation use. Other factors affecting our Utility Members’ usage of electricity include:
the amount, size and usage of machinery and electronic equipment;
the expansion or contraction of operations among our Utility Members’ commercial and industrial customers;
the general growth in population; and
economic conditions.
Impacts of Supply Chain and Inflation
Our ability to meet our Utility Members' electric power requirements and complete our capital projects is dependent on maintaining an efficient supply chain. The procurement and delivery of materials and equipment have been impacted by the current domestic and global supply chain disruptions. We are experiencing longer lead-times on the procurement of certain materials and equipment. Inflation has contributed to higher prices for materials and equipment. We continue to monitor potential impacts to our operations and estimated capital expenditures and timing of projects related to inflationary pressures and supply chain disruptions.
Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023
Operating Revenues
Our operating revenues are primarily derived from electric power sales to our Utility Members and non-member purchasers. Other operating revenue consists primarily of wheeling, transmission, leasing, and coal sales. Other operating revenue also includes revenue we receive from certain of our Non-Utility Members. The following is a comparison of our
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operating revenues and energy sales in MWh by type of purchaser for the three months ended September 30, 2024 and 2023 (dollars in thousands):
Three Months Ended September 30,Period-to-period Change
20242023AmountPercent
Operating revenues
Utility Member electric sales$309,599 $357,576 $(47,977)(13.4)%
Non-member electric sales73,943 51,294 22,649 44.2 %
Rate stabilization108,222 14,041 94,181 670.8 %
Provision for rate refunds— (210)210 (100.0)%
Other37,119 15,618 21,501 137.7 %
Total operating revenues$528,883 $438,319 $90,564 20.7 %
Energy sales (in MWh):
Utility Member electric sales4,015,2324,730,452 (715,220)(15.1)%
Non-member electric sales631,218 608,201 23,017 3.8 %
4,646,450 5,338,653 (692,203)(13.0)%
Excluding United Power, Utility Member load growth increased 159,548 MWh, or 4.1 percent, during the three months ended September 30, 2024 compared to the same period in 2023. The United Power membership withdrawal on May 1, 2024 resulted in a decrease of 874,768 MWh sold to United Power for the three months ended September 30, 2024 compared to the same period in 2023. The impact of the United Power membership withdrawal to total Utility Member electric sales (in dollars and MWhs) was lower than anticipated due to the load growth from our remaining Utility Members, and an increase in non-member electric sales.
Non-member electric sales revenue increased primarily due to higher long-term sales. Long-term sales increased 321,007 MWhs, or 281.9 percent, to 434,886 MWhs for the three months ended September 30, 2024 compared to 113,879 MWhs for the same period in 2023. Partially offsetting the increase in long-term sales, short-term market sales decreased 292,989 MWh, or 60.3 percent, to 196,333 MWh for the three months ended September 30, 2024 compared to 494,322 MWh for the same period in 2023. The ability to sell excess power to non-members after United Power's membership withdrawal contributed significantly to the increase in non-member electric sales.
We recognized $108.2 million of previously deferred membership withdrawal income during the three months ended September 30, 2024 compared to $14.0 million during the same period in 2023 as part of our rate stabilization measures. This includes $76.4 million that we recognized in September 2024 to offset the expense recognition related to the $68.2 million write off of the J.M. Shafer Generating Station and Colowyo Coal acquisition costs/goodwill and $8.2 million in accelerated expenses related to the transition from mining to full reclamation at the Colowyo Mine in 2025. We expect to recognize additional previously deferred membership withdrawal during the remainder of 2024.
Other operating revenue increased primarily due to the sale of excess intangible assets and an increase in lease revenue related to a tolling agreement for our two 70 MW units at the Knutson Generating Station for all capacity and energy through the operation of both units that started on May 1, 2024.
Operating Expenses
Our operating expenses are primarily comprised of the costs that we incur to supply and transmit our Utility Members’ electric power requirements through a portfolio of resources, including generation and transmission facilities, long-term purchase contracts and short-term energy purchases and the costs associated with any sales of power to non-members.
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The following is a summary of the components of our operating expenses for the three months ended September 30, 2024 and 2023 (dollars in thousands):
Three Months Ended September 30,Period-to-period Change
20242023AmountPercent
Operating expenses
Purchased power$123,437 $120,250 $3,187 2.7 %
Fuel59,271 71,241 (11,970)(16.8)%
Production40,192 44,758 (4,566)(10.2)%
Transmission47,984 47,098 886 1.9 %
General and administrative32,430 19,663 12,767 64.9 %
Depreciation, amortization and depletion60,277 43,120 17,157 39.8 %
Coal mining3,238 3,834 (596)(15.5)%
Goodwill impairment68,223 — 68,223 N/A
Other4,471 2,345 2,126 90.7 %
Total operating expenses$439,523 $352,309 $87,214 24.8 %

Fuel expense decreased primarily due to a lower average rate for natural gas of 147.9 percent, a decrease of 486,426 MWhs in generation by our coal-fired generating facilities, and a decrease of 39,214 MWhs in generation by our natural gas-fired generating facilities, during the three months ended September 30, 2024 compared to the same period in 2023.
Depreciation, amortization and depletion increased primarily due to accelerated depreciation and amortization from the transition from mining to reclamation at Colowyo Mine.
Goodwill impairment is due to the expense recognition related to the write off of the J.M. Shafer Generating Station and Colowyo Coal acquisition costs/goodwill.
Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023
Operating Revenues
The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the nine months ended September 30, 2024 and 2023 (dollars in thousands):
Nine Months Ended September 30,Period-to-period Change
20242023AmountPercent
Operating revenues
Utility Member electric sales$863,711 $923,977 $(60,266)(6.5)%
Non-member electric sales148,330 111,729 36,601 32.8 %
Rate stabilization125,123 36,862 88,261 239.4 %
Provision for rate refunds— 94 (94)(100.0)%
Other80,767 48,162 32,605 67.7 %
Total operating revenues1,217,931 1,120,824 $97,107 8.7 %
Energy sales (in MWh):
Utility Member electric sales11,716,367 12,526,839 (810,472)(6.5)%
Non-member electric sales1,712,447 1,228,853 483,594 39.4 %
13,428,814 13,755,692 (326,878)(2.4)%

Excluding United Power, Utility Member load growth increased 531,960 MWh, or 5.3 percent, for the nine months ended September 30, 2024 compared to the same period in 2023. The United Power membership withdrawal on May 1, 2024 resulted in a decrease of 1,342,432 MWh sold to United Power for the nine months ended September 30, 2024 compared to the same period in 2023. The impact of the United Power membership withdrawal to total Utility Member electric sales (in dollars and MWhs) was lower than anticipated due to the load growth from our remaining Utility Members, and an increase in non-member electric sales.
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Non-member electric sales increased primarily due to higher long-term sales. Long-term sales increased 796,452 MWhs, or 373.0 percent, to 1,009,992 MWhs for the nine months ended September 30, 2024 compared to 213,540 MWhs for the same period in 2023. Partially offsetting the increase in long-term sales (in dollars and MWhs), short-term market sales decreased 312,858 MWh, or 30.8 percent to 702,455 MWhs for the nine months ended September 30, 2024 compared to 1,015,313 MWhs for the same period in 2023. The ability to sell excess power to non-members after United Power’s membership withdrawal contributed significantly to the increase in non-member electric sales.
We recognized $125.1 million of deferred membership withdrawal income during the nine months ended September 30, 2024 compared to $36.9 million of deferred membership withdrawal during the same period in 2023 as part of our rate stabilization measures. This includes $76.4 million that we recognized in September 2024 to offset the expense recognition related to the $68.2 million write off of the J.M. Shafer Generating Station and Colowyo Coal acquisition costs/goodwill and $8.2 million in accelerated expenses related to the transition from mining to full reclamation at the Colowyo Mine in 2025. We expect to recognize additional previously deferred membership withdrawal income during the remainder of 2024.
Other operating revenue increased primarily due to the sale of intangible assets and an increase in lease revenue related to a tolling agreement for our two 70 MW units at the Knutson Generating Station for all capacity and energy through the operation of both units that started on May 1, 2024.
Operating Expenses
The following is a summary of the components of our operating expenses for the nine months ended September 30, 2024 and 2023 (dollars in thousands):
Nine Months Ended September 30,Period-to-period Change
20242023AmountPercent
Operating expenses
Purchased power315,347 316,356 $(1,009)(0.3)%
Fuel167,819 197,944 (30,125)(15.2)%
Production129,375 142,733 (13,358)(9.4)%
Transmission140,506 142,406 (1,900)(1.3)%
General and administrative77,993 61,738 16,255 26.3 %
Depreciation, amortization and depletion149,053 128,191 20,862 16.3 %
Coal mining5,343 9,603 (4,260)(44.4)%
Goodwill impairment68,223 — 68,223 N/A
Other10,671 11,057 (386)(3.5)%
Total operating expenses$1,064,330 $1,010,028 $54,302 5.4 %

Fuel expense decreased due to a decrease of 885,089 MWhs in generation by our coal-fired generating facilities, a decrease of 190,542 MWhs in generation by our natural gas-fired generating facilities, a lower average rate for natural gas of 42.3 percent, and a lower average rate for coal of 5.6 percent for the nine months ended September 30, 2024 compared to the same period in 2023.
Production expense decreased due to lower maintenance expenses of $12.5 million for the nine months ended September 30, 2024 compared to the same period in 2023.
Depreciation, amortization and depletion increased primarily due to accelerated depreciation and amortization from the transition from mining to reclamation at Colowyo Mine.
Goodwill impairment is due to the expense recognition related to the write off of the J.M. Shafer Generating Station and Colowyo Coal acquisition costs/goodwill.
Financial Condition as of September 30, 2024 Compared to December 31, 2023
The principal changes in our financial condition from December 31, 2023 to September 30, 2024 were due to increases and decreases in the following:
Assets
Construction work in progress increased $109.3 million, or 66.7 percent, to $273.3 million as of September 30, 2024 compared to $164.0 million as of December 31, 2023. The increase was primarily due to the Axial Basin Solar and the
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Dolores Canyon Solar facility purchases and construction costs, capital expenditures for various transmission and generation projects and migrating and upgrading software systems to hosted solutions.
Restricted cash and investments-current increased $16.9 million to $17.6 million as of September 30, 2024 compared to $0.7 million as of December 31, 2023. The increase was primarily due $16.9 million that was deposited with our Master Indenture trustee in September 2024 in advance of our October 1, 2024 debt service payments for the 2014 Private Placement and Moffat County Pollution Control Bonds. In accordance with our Master Indenture, we are required to fund the account one day prior to debt service payments.
Deposits and advances increased $45.6 million to $79.0 million as of September 30, 2024 compared to $37.5 million as of December 31, 2023. The increase was primarily due to migrating and upgrading software solutions to hosted solutions and prepayments of annual insurance, memberships and licenses. These prepayments are being amortized to expense over the term of the related insurance, membership or license period.
Liabilities
Short-term borrowings decreased $109.7 million to $74.6 million as of September 30, 2024 compared to $184.3 million as of December 31, 2023. The majority of the decrease was due to operating cash flow.
Regulatory liabilities increased $582.1 million to $584.4 million as of September 30, 2024 compared to $2.3 million as of December 31, 2023. The increase was primarily due to United Power's $709.4 million contract termination payment amount arising from their withdrawal from membership in us and the termination of their wholesale electric service contract with us. Our Board deferred as a regulatory liability $530.1 million of United Power's contract termination payment amount. The remaining $179.3 million was related to a transmission credit for the portion of transmission debt allocated to United Power and required to be deferred pursuant to FERC's December 2023 order and Rate Schedule 281. Regulatory liabilities was also impacted by the recognition of deferred membership withdrawal of $125.1 million during the nine month period ended September 30, 2024 as part of our rate stabilization measures. This includes $76.4 million that we recognized in September 2024 to offset the expense recognition related to the $68.2 million write off of the J.M. Shafer Generating Station and Colowyo Coal acquisition costs/goodwill and $8.2 million in accelerated expenses related to the transition from mining to full reclamation at the Colowyo Mine in 2025.
Liquidity and Capital Resources
We finance our operations, working capital needs and capital expenditures from operating revenues and issuance of short-term and long-term borrowings. As of September 30, 2024, we had $293.6 million in cash and cash equivalents. Our committed credit arrangement as of September 30, 2024 is as follows (dollars in thousands):
Authorized
Amount
Available
September 30,
2024
2022 Revolving Credit Agreement$520,000 (1)$445,472 (2)

(1)The amount of this facility that can be used to support commercial paper is limited to $500 million.
(2)The portion of this facility that was unavailable as of September 30, 2024 was $75 million which was dedicated to support outstanding commercial paper.
We have a secured 2022 Revolving Credit Agreement with aggregate commitments of $520 million. The 2022 Revolving Credit Agreement includes a swingline sublimit of $125 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million, of which $125 million of the swingline sublimit, $75 million of the letter of credit sublimit, and $425 million of the commercial paper back-up sublimit remained available as of September 30, 2024.
The 2022 Revolving Credit Agreement is secured under our Master Indenture and has a maturity date of April 25, 2027, unless extended as provided therein. Funds advanced under the 2022 Revolving Credit Agreement bear interest either at adjusted Term SOFR rates or alternative base rates, at our option. The adjusted Term SOFR rate is the Term SOFR rate for the term of the advance plus a margin (1.250 percent as of September 30, 2024) based on our credit ratings. Base rate loans bear interest at the alternate base rate plus a margin (0.250 percent as of September 30, 2024) based on our credit ratings. The alternate base rate is the highest of (a) the federal funds rate plus ½ of 1.00 percent, (b) the prime rate, and (c) the adjusted Term SOFR rate plus 1.00 percent.
The 2022 Revolving Credit Agreement contains customary representations, warranties, covenants, events of default and acceleration, including financial DSR and ECR requirements in line with the covenants contained in our Master Indenture. A violation of these covenants would result in the inability to borrow under the facility.
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Under our commercial paper program, our Board authorized us to issue commercial paper in amounts that do not exceed the commercial paper back-up sublimit under our 2022 Revolving Credit Agreement, which was $500 million as of September 30, 2024, thereby providing 100 percent dedicated support for any commercial paper outstanding. As of September 30, 2024, we had $75 million commercial paper outstanding and $425 million available on the commercial paper back-up sublimit. See Note 8 to the Unaudited Consolidated Financial Statements in Item 1 for further information.
We entered into both a loan agreement and security agreement, dated October 1, 2024, with RUS, a part of the USDA, for a $75 million zero percent interest loan. The loan agreement includes financial DSR requirements in line with the covenants contained in our Master Indenture. This loan was provided by RUS as part of the Rural Energy Savings Program pursuant to the Farm Security and Rural Investment Act of 2002. We can draw up to $50 million of this loan as part of our new Electrify and Save® On-Bill Repayment Program that allows our Utility Members’ customers to install energy efficiency measures, at no up-front cost, and repay over time through their monthly utility bill from our Utility Members the costs of the measures and installation, at low interest rates. The remaining $25 million may be used as permitted in our work plan with RUS. Other than a special draw of $3 million that is due at maturity, each draw must be repaid within 10 years. The loan has a final maturity of October 1, 2044 and is not secured under our Master Indenture, but rather secured by certain depository accounts related to the On-Bill Repayment Program and certain rights in our On-Bill Repayment Program.
As a requirement of the loan from RUS, we must maintain a letter of credit for the benefit of RUS equal to 50 percent of the amount drawn and outstanding from the loan. We expect to make an initial special draw of $3 million and have provided RUS a letter of credit for $3 million issued under our 2022 Revolving Credit Agreement for the $3 million special draw and expected upcoming draws as part of our On-Bill Repayment Program.
Our First Mortgage Bonds, Series 2014E-1 with $128 million outstanding matured on November 1, 2024. The bonds were paid off in full at maturity on November 1, 2024.
We have previously purchased our outstanding debt through cash purchases in open market purchases. In the future, we may from time to time purchase additional outstanding debt through cash purchases and/or exchanges for other securities, in open market purchases, privately negotiated transactions, additional tender offers, or otherwise and may continue to seek to retire or purchase our outstanding debt in the future. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We are mindful of our debt and its maturities and we continually evaluate options to ensure that our balance sheet and capital structure is aligned with our business and the long-term health of our company.
We believe we have sufficient liquidity to fund operations and capital financing needs from projected cash on hand, restricted cash, our commercial paper program, the 2022 Revolving Credit Agreement, and contract termination payments from withdrawing Utility Members.
Cash Flow
Cash is provided by operating activities and issuance of debt. Capital expenditures and debt service payments comprise a significant use of cash.
Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023
Operating activities. Net cash provided by operating activities was $865.2 million for the nine months ended September 30, 2024 compared to $104.7 million for the same period in 2023, an increase in net cash provided by operating activities of $760.5 million. The increase in net cash provided by operating activities was primarily impacted by United Power's contract termination payment of $709.4 million. Additionally, cash provided by operating activities was also impacted by the timing of cash collected from Member accounts receivable, payment of trade payables and accrued expenses and prepayments of annual insurance.
Investing activities. Net cash used in investing activities was $218.2 million for the nine months ended September 30, 2024 compared to $117.0 million for the same period in 2023, an increase in net cash used in investing activities of $101.2 million. The increase in net cash used in investing activities was impacted by additional investments in utility plant and timing of payments we made to operating agents of jointly owned facilities to fund our share of costs to be incurred under each project. Additionally, on May 8, 2024, we sold to United Power certain assets for $75 million that were primarily used to serve United Power's load.
Financing activities. Net cash used in financing activities was $443.5 million for the nine months ended September 30, 2024 compared to net cash provided by financing activities of $90.5 million for the same period in 2023, a decrease in net cash
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provided by financing activities of $534.0 million. The decrease in net cash provided by financing activities was primarily due using some of United Power's contract termination payment to payoff the 2023 multiple advance rate term loan and also paying down short-term borrowings. Additionally, financing activities was impacted by a patronage capital retirement of $82.2 million resulting from United Power's withdrawal, with the amount of the discounted patronage capital credit applied to United Power's contract termination payment.
Capital Expenditures
We forecast our capital expenditures annually as part of our long-term planning. We regularly review these projections to update our calculations to reflect changes in our future plans, facility closures, facility costs, market factors and other items affecting our forecasts. After taking into account our our preferred IRA scenario as part of Phase I of our 2023 ERP, in the years 2024 through 2028, we forecast that we may invest approximately $2.60 billion in new facilities and upgrades to our existing facilities.
Our actual capital expenditures depend on a variety of factors, including assumptions related to our Responsible Energy Plan and Phase I of our 2023 ERP, receipt of New ERA Program funding and other federal programs, Utility Member load growth or Utility Member withdraws, Bring Your Own Resource Program, availability of necessary permits, regulatory changes, environmental requirements, construction delays and costs, supply chain issues, inflation, and ability to access capital in credit markets. Thus, actual capital expenditures may vary significantly from our projections.
Capital projects include several transmission projects to improve reliability and load-serving capability throughout our service area.
Changing Environmental Regulations
We are subject to various federal, state and local laws, rules and regulations with regard to air quality, including greenhouse gases, water quality, and other environmental matters. These environmental laws, rules and regulations are complex and change frequently. Following are updates on recent developments that may impact us:
Air Quality
Mercury and other Hazardous Air Pollutants. In May 2024, the EPA published final revisions to the National Emission Standards for Hazardous Air Pollutants for coal- and oil-fired electric utility steam generating units pursuant to EPA’s risk and technology review as required by Section 112 of the Clean Air Act. The EPA finalized a more stringent emission limit for particulate matter, as a surrogate for non-mercury metals, and requirements for installations of particulate matter continuous emissions monitoring systems. We are assessing options related to these requirements. The revisions are subject to litigation.
Greenhouse Gas Regulation. In May 2024, the EPA published a final rule regarding emission guidelines for carbon dioxide from certain existing electric generating units under Section 111(d) of the Clean Air Act and certain new electric generating units under Section 111(b) of the Clean Air Act. EPA finalized a matrix of emission requirements that depend on a given unit’s fuel type, generating capacity, capacity factor, and years of continued operation. Due to applicability thresholds and previously announced retirement dates of our generating facilities, this particular rule does not, or likely will not, affect most of our generating facilities. However, if not overturned, the rule will drive important decision-making about future operation of and investment in Laramie River Generating Station. The regulation is subject to litigation.
Other Environmental Matters
Coal Ash Regulation. In May 2024, the EPA published a final rule regarding groundwater monitoring, corrective action, closure, and post-closure care requirements for all coal combustion residuals management units under the Resource Conservation and Recovery Act. We are analyzing the final rule for possible impacts on our operations.
For further discussion regarding potential effects on our business from environmental regulations, see "Item 1 – BUSINESS — ENVIRONMENTAL REGULATION" and "Item 1 – RISK FACTORS" in our annual report on Form 10-K for the year ended December 31, 2023.
Rating Triggers
Our current senior secured ratings are “Baa1 (stable outlook)” by Moody’s, “BBB (stable outlook)” by S&P, and “BBB+ (negative outlook)” by Fitch. Our current short-term ratings are “A-2” by S&P and “F1” by Fitch.
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Our 2022 Revolving Credit Agreement includes a pricing grid related to the Term SOFR spread, commitment fee and letter of credit fees due under the facility. A downgrade of our senior secured ratings could result in an increase in each of these pricing components. We do not believe that any such increase would have a material adverse effect on our financial condition or our future results of operations. However, a downgrade of our senior secured ratings could impact the costs associated with incurring additional debt and could make accessing the debt markets on favorable terms more difficult.
We currently have contracts and other obligations that require adequate assurance of performance. These include organized markets contracts, power contracts, natural gas supply contracts and financial risk management contracts. Some of the contracts are directly tied to us maintaining investment grade credit ratings by S&P and Moody’s. We may enter into additional contracts which may contain adequate assurance requirements. If we are required to provide adequate assurances, it may impact our liquidity and the amount of adequate assurance required will be dependent on our credit ratings.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
There have been no material changes to market risks during the most recent fiscal quarter from those reported in our annual report on Form 10-K for the year ended December 31, 2023.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.
Changes in Internal Controls
During the third quarter of 2024, we completed the migration and upgrade to a new hosted software solution for our accounting and supply chain management systems, along with other systems. The implementation and migration of the new software solution results in material changes to our internal controls over financial reporting. We have updated the internal controls as appropriate and will continue to monitor the impact of the new software solution on our financial reporting business processes. Other than related to the new software solution, there were no changes that occurred during the third quarter ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Information required by this Item is contained in Note 18 to the Unaudited Consolidated Financial Statements in Item 1.
Item 4. Mine Safety Disclosures
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this quarterly report on Form 10-Q.
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Item 6. Exhibits
Exhibit NumberDescription of Exhibit
31.1
31.2
32.1
32.2
95
101XBRL Interactive Data File.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Tri-State Generation and Transmission
Association, Inc.
Date: November 8, 2024By:/s/ Duane Highley
Duane Highley
Chief Executive Officer
Date: November 8, 2024/s/ Todd E. Telesz
Todd E. Telesz
Senior Vice President/Chief Financial Officer (Principal Financial Officer)

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