Hallador Energy 10Q 2024 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2024

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number:001-34743

HALLADOR ENERGY COMPANY

(www.halladorenergy.com)


Colorado	84-1014610
(State of incorporation)	(IRS Employer Identification No.)

1183 East Canvasback Drive, Terre Haute, Indiana	47802
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 812.299.2800

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Shares, $.01 par value	HNRG	Nasdaq

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 ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations 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 ☑

As of November 7, 2024, we had 42,617,108 shares of common stock outstanding.

Table of Contents

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION	1

ITEM 1. FINANCIAL STATEMENTS (Unaudited)	1

Condensed Consolidated Balance Sheets	1

Condensed Consolidated Statements of Operations	2

Condensed Consolidated Statements of Cash Flows	4

Condensed Consolidated Statements of Stockholders’ Equity	5

Notes to Condensed Consolidated Financial Statements	6

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	20

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	31

ITEM 4. CONTROLS AND PROCEDURES	32

PART II - OTHER INFORMATION	33

ITEM 4. MINE SAFETY DISCLOSURES	33

ITEM 6. EXHIBITS	33

SIGNATURES	34

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Hallador Energy Company

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

(unaudited)


	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	3,829	$	2,842
Restricted cash		5,812		4,281
Accounts receivable		11,908		19,937
Inventory		31,077		23,075
Parts and supplies		39,663		38,877
Prepaid expenses		5,964		2,262
Assets held-for-sale		1,544		1,611
Total current assets		99,797		92,885
Property, plant and equipment:
Land and mineral rights		115,486		115,486
Buildings and equipment		529,818		537,131
Mine development		167,077		158,642
Finance lease right-of-use assets		19,869		12,346
Total property, plant and equipment		832,250		823,605
Less - accumulated depreciation, depletion and amortization		(360,173)		(334,971)
Total property, plant and equipment, net		472,077		488,634
Investment in Sunrise Energy		2,071		2,811
Other assets		5,785		5,450
Total assets	$	579,730	$	589,780

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net	$	24,095	$	24,438
Accounts payable and accrued liabilities		42,915		62,908
Current portion of lease financing		6,248		3,933
Deferred revenue		57,293		23,062
Contract liability - power purchase agreement and capacity payment reduction		41,049		43,254
Total current liabilities		171,600		157,595
Long-term liabilities:
Bank debt, net		42,918		63,453
Convertible notes payable		—		10,000
Convertible notes payable - related party		—		9,000
Long-term lease financing		9,234		8,157
Deferred income taxes		5,846		9,235
Asset retirement obligations		15,746		14,538
Contract liability - power purchase agreement		13,456		47,425
Other		2,133		1,789
Total long-term liabilities		89,333		163,597
Total liabilities		260,933		321,192
Commitments and contingencies
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued		—		—
Common stock, $.01 par value, 100,000 shares authorized; 42,599 and 34,052 issued and outstanding, as of September 30, 2024 and December 31, 2023, respectively		426		341
Additional paid-in capital		188,018		127,548
Retained earnings		130,353		140,699
Total stockholders’ equity		318,797		268,588
Total liabilities and stockholders’ equity	$	579,730	$	589,780

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
SALES AND OPERATING REVENUES:
Electric sales	$	71,715	$	67,403	$	191,861	$	230,812
Coal sales		31,662		97,420		114,093		280,596
Other revenues		1,667		945		4,221		3,888
Total sales and operating revenues		105,044		165,768		310,175		515,296
EXPENSES:
Fuel		13,176		11,345		31,674		99,959
Other operating and maintenance costs		33,320		65,551		106,714		139,979
Cost of purchased power		3,149		—		7,694		—
Utilities		3,185		4,507		10,955		13,347
Labor		26,721		37,639		88,444		114,698
Depreciation, depletion and amortization		13,838		16,230		42,930		51,375
Asset retirement obligations accretion		410		468		1,208		1,380
Exploration costs		62		171		179		682
General and administrative		6,471		6,054		20,218		18,596
Total operating expenses		100,332		141,965		310,016		440,016

INCOME FROM OPERATIONS		4,712		23,803		159		75,280

Interest expense (1)		(2,692)		(3,030)		(10,364)		(10,470)
Loss on extinguishment of debt		—		(1,491)		(2,790)		(1,491)
Equity method investment (loss)		(234)		(177)		(740)		(325)
NET INCOME (LOSS) BEFORE INCOME TAXES		1,786		19,105		(13,735)		62,994

INCOME TAX EXPENSE (BENEFIT):
Current		—		(178)		—		315
Deferred		232		3,208		(3,389)		7,638
Total income tax expense (benefit)		232		3,030		(3,389)		7,953

NET INCOME (LOSS)	$	1,554	$	16,075	$	(10,346)	$	55,041

NET INCOME (LOSS) PER SHARE:
Basic	$	0.04	$	0.49	$	(0.27)	$	1.66
Diluted	$	0.04	$	0.44	$	(0.27)	$	1.52

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		42,598		33,140		38,455		33,088
Diluted		43,018		36,848		38,455		36,748

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(1) Interest Expense:
Interest on bank debt	$	2,073	$	2,006	$	7,657	$	6,316
Other interest		181		422		1,456		1,316
Amortization:
Amortization of debt issuance costs		438		602		1,251		2,838
Total amortization		438		602		1,251		2,838
Total interest expense	$	2,692	$	3,030	$	10,364	$	10,470

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)


	Nine Months Ended September 30,
	2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(10,346)	$	55,041
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax (benefit)		(3,389)		7,638
Equity loss – Sunrise Energy		740		325
Cash distribution - Sunrise Energy		-		625
Depreciation, depletion, and amortization		42,930		51,375
Loss on extinguishment of debt		2,790		1,491
Loss (gain) on sale of assets		(536)		78
Amortization of debt issuance costs		1,251		2,838
Asset retirement obligations accretion		1,208		1,380
Cash paid on asset retirement obligation reclamation		(820)		(2,286)
Stock-based compensation		3,320		2,774
Amortization of contract asset and contract liabilities		(36,174)		(32,444)
Other		1,352		914
Change in operating assets and liabilities:
Accounts receivable		8,029		9,197
Inventory		(8,002)		14,874
Parts and supplies		(786)		(8,717)
Prepaid expenses		(1,098)		1,116
Accounts payable and accrued liabilities		(7,715)		(11,419)
Deferred revenue		34,231		(15,273)
Net cash provided by operating activities		26,985		79,527
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(39,606)		(48,746)
Proceeds from sale of equipment		3,373		62
Net cash used in investing activities		(36,233)		(48,684)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt		(86,500)		(56,463)
Borrowings of bank debt		65,000		33,000
Payments on lease financing		(4,105)		—
Proceeds from sale and leaseback arrangement		3,783		—
Issuance of related party notes payable		5,000		—
Payments on related party notes payable		(5,000)		—
Debt issuance costs		(654)		(5,940)
ATM offering		34,515		—
Taxes paid on vesting of RSUs		(273)		(1,150)
Net cash provided by (used in) financing activities		11,766		(30,553)
Increase in cash, cash equivalents, and restricted cash		2,518		290
Cash, cash equivalents, and restricted cash, beginning of period		7,123		6,426
Cash, cash equivalents, and restricted cash, end of period	$	9,641	$	6,716
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents	$	3,829	$	2,573
Restricted cash		5,812		4,143
	$	9,641	$	6,716
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	8,679	$	8,069
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense	$	(7,825)	$	3,214
Stock issued on redemption of convertible notes and interest	$	22,993	$	—

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(unaudited)


				Additional				Total
	Common Stock Issued			Paid-in		Retained		Stockholders’
	Shares	Amount		Capital		Earnings		Equity
Balance, June 30, 2024	42,599	$	426	$	186,945	$	128,799	$	316,170
Stock-based compensation	—		—		1,073		—		1,073
Net income	—		—		—		1,554		1,554
Balance, September 30, 2024	42,599	$	426	$	188,018	$	130,353	$	318,797

Balance, December 31, 2023	34,052	$	341	$	127,548	$	140,699	$	268,588
Stock-based compensation	—		—		3,320		—		3,320
Stock issued on vesting of RSUs	379		4		(4)		—		—
Taxes paid on vesting of RSUs	(159)		(2)		(271)		—		(273)
Stock issued on redemption of convertible notes	3,672		36		22,957		—		22,993
Stock issued in ATM offering	4,655		47		34,468		—		34,515
Net loss	—		—		—		(10,346)		(10,346)
Balance, September 30, 2024	42,599	$	426	$	188,018	$	130,353	$	318,797


				Additional				Total
	Common Stock Issued			Paid-in		Retained		Stockholders’
	Shares	Amount		Capital		Earnings		Equity
Balance, June 30, 2023	33,137	$	332	$	119,678	$	134,872	$	254,882
Stock-based compensation	—		—		773		—		773
Stock issued on vesting of RSUs	10		—		—		—		—
Taxes paid on vesting of RSUs	(5)		—		(41)		—		(41)
Net income	—		—		—		16,075		16,075
Balance, September 30, 2023	33,142	$	332	$	120,410	$	150,947	$	271,689

Balance, December 31, 2022	32,983	$	330	$	118,788	$	95,906	$	215,024
Stock-based compensation	—		—		2,774		—		2,774
Stock issued on vesting of RSUs	285		3		(3)		—		—
Taxes paid on vesting of RSUs	(126)		(1)		(1,149)		—		(1,150)
Net income	—		—		—		55,041		55,041
Balance, September 30, 2023	33,142	$	332	$	120,410	$	150,947	$	271,689

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Notes to Condensed Consolidated Financial Statements

(unaudited)

(1)	GENERAL BUSINESS

The condensed consolidated financial statements include the accounts of Hallador Energy Company (hereinafter known as “we, us, or our”) and its wholly owned subsidiaries Sunrise Coal, LLC (“Sunrise”), Hallador Power Company, LLC (“Hallador Power”), as well as Sunrise and Hallador Power’s wholly owned subsidiaries.

We strategically view and manage our operations through two reportable segments: Electric Operations and Coal Operations. The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant. The Coal Operations reportable segment includes mining complexes Oaktown 1 and 2 underground mines, Prosperity surface mine, Freelandville surface mine, and Carlisle wash plant. On February 23, 2024, our Coal Operations Segment committed to a reorganization effort designed to strengthen its financial and operational efficiency and create significant operational savings and higher margins. For further information, see “Note 16 – Organizational Restructuring” below. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” and primarily are comprised of unallocated corporate costs and activities, the elimination of coal sales from coal operations to electric operations, a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method, and our wholly-owned subsidiary Summit Terminal LLC (“Summit”), a logistics transport facility located on the Ohio River. See “Note 20 – Assets Held-for-Sale” for further discussion on Summit.

All significant intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the Company’s prior period condensed consolidated financial information to conform to the current period presentation. These presentation changes did not impact the Company’s condensed consolidated net income (loss), consolidated cash flows, total assets, total liabilities or total stockholders’ equity.

The interim financial data is unaudited; however, in our opinion, it includes all adjustments, consisting only of normal recurring adjustments necessary for a fair statement of the results for the interim periods. The condensed consolidated financial statements included herein have been prepared pursuant to the Securities and Exchange Commission’s (the “SEC”) rules and regulations; accordingly, certain information and footnote disclosures normally included in generally accepted accounting principles (“GAAP”) financial statements have been condensed or omitted.

The results of operations and cash flows for the three and nine months ended September 30, 2024, are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2024.

Our organization and business, the accounting policies we follow, and other information are contained in the notes to our consolidated financial statements filed as part of our 2023 Annual Report on Form 10-K. This quarterly report should be read in conjunction with such Annual Report on Form 10-K.

(2)	RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 primarily requires enhanced disclosures about significant segment expenses regularly provided to the chief operating decision maker (“CODM”), the amount and composition of other segment items, and the title and position of the CODM. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-07, but do not expect it to have a material effect on our consolidated financial statements.

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In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-09, but do not expect it to have a material effect on our consolidated financial statements.

(3)	LONG-LIVED ASSET IMPAIRMENTS

Long-lived assets are reviewed for impairment whenever events or changes in circumstance indicate that the carrying amount of the assets may not be recoverable. For the three and nine months ended September 30, 2024 and 2023, no impairment charges were recorded for long-lived assets.

(4)

INVENTORY

Inventory is valued at a lower of cost or net realizable value (NRV). As of September 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $1.8 million and $2.0 million, respectively.

(5)

BANK DEBT

On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC Bank, National Association (in its capacity as administrative agent, "PNC"), which was accounted for as a debt modification. The primary purpose of the First Amendment was to provide the Company with short-term covenant relief to pursue additional liquidity. The First Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repays outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a maximum of $20.0 million. These required prepaid forward power sale Term Loan repayments, if any, will take the place of the $6.5 million quarterly Term Loan payments. Furthermore, the First Amendment defines certain administrative changes which include, among other things, added requirements related to reporting, third party financial advisors, and appraisals on coal and power assets.

Bank debt was reduced by $21.5 million during the nine months ended September 30, 2024. Bank debt is comprised of our Term Loan ($45.5 million as of September 30, 2024) and a $75.0 million revolver ($24.5 million borrowed as of September 30, 2024) under the Credit Agreement. The term debt required quarterly payments of $6.5 million starting in April 2024 through maturity. Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.

Liquidity

As of September 30, 2024, we had additional borrowing capacity of $31.1 million under the revolver and total liquidity of $34.9 million. Our additional borrowing capacity is net of $19.4 million in outstanding letters of credit that we were required to maintain for surety bonds and $24.5 million drawn on the revolver at September 30, 2024. Liquidity consists of our additional borrowing capacity and cash and cash equivalents.

Fees

Unamortized bank fees and other costs incurred in connection with our initial facility totaled $4.3 million. Additional costs incurred with the First Amendment totaled $0.6 million. These unamortized bank fees were deferred and are being amortized over the term of the loan. Unamortized bank fees as of September 30, 2024, and December 31, 2023, were $3.0 million and $3.6 million, respectively.

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Bank debt, less debt issuance costs, is presented below (in thousands):


	September 30,		December 31,
	2024		2023
Current bank debt	$	26,000	$	26,000
Less unamortized debt issuance cost		(1,905)		(1,562)
Net current portion	$	24,095	$	24,438

Long-term bank debt	$	44,000	$	65,500
Less unamortized debt issuance cost		(1,082)		(2,047)
Net long-term portion	$	42,918	$	63,453

Total bank debt	$	70,000	$	91,500
Less total unamortized debt issuance cost		(2,987)		(3,609)
Net bank debt	$	67,013	$	87,891


Future Maturities (in thousands):
2024	$	6,500
2025		26,000
2026		37,500
Total	$	70,000

Covenants

The First Amendment, among other things, provided the Company with short-term covenant relief to pursue additional liquidity. The First Amendment waived the Company’s Leverage Ratio requirement for the third and fourth quarters of 2024, increased the threshold to 5.50 to 1.00 for the first quarter of 2025, and decreased the threshold back to 2.25 to 1.00 for each fiscal quarter thereafter. Additionally, the Debt Service Coverage Ratio requirement (1.25 to 1.00) was waived from third quarter of 2024 through the first quarter of 2025. The First Amendment also added additional financial covenants which include: (i) a maximum First Lien Leverage Ratio for the first quarter of 2025, calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 3.50 to 1.00; (ii) a minimum liquidity requirement of $10.0 million, beginning on the First Amendment execution date and ending when the second quarter of 2025 compliance certificate is received; and (iii) a minimum quarterly EBITDA requirement, as defined in the First Amendment, of $5.0 million for the third quarter of 2024 through the first quarter of 2025. As of September 30, 2024, our liquidity of $34.9 million and quarterly EBITDA of $9.6 million were in compliance with the requirements of the Credit Agreement.

As of September 30, 2024, we were in compliance with all other covenants defined in the Credit Agreement.

Interest Rate

The interest rate on the facility ranges from SOFR plus 4.00% to SOFR plus 5.00%, depending on our Leverage Ratio. As of September 30, 2024, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 9.76%.

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(6)	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consist of the following for the indicated dates (in thousands):


	September 30,		December 31,
	2024		2023
Accounts payable	$	23,437	$	43,636
Accrued property taxes		4,808		2,987
Accrued payroll		5,123		6,575
Workers' compensation reserve		4,397		3,629
Group health insurance		1,750		2,300
Asset retirement obligation - current portion		1,330		2,150
Other		2,070		1,631
Total accounts payable and accrued liabilities	$	42,915	$	62,908

(7)

REVENUE

Revenue from Contracts with Customers

We account for a contract with a customer when the parties have approved the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all the consideration will be collected. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer.

Electric operations

We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), is met at the time a PPA is executed by the parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.

We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract capacity performance obligations and daily, based on an output method of MWh of electricity delivered.

For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier. For delivered energy to all other customers, we recognize revenue daily for the actual delivered electricity.

Coal operations

Our coal revenue is derived from sales to customers of coal produced at our facilities. Our customers typically purchase coal directly from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.

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Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as Btu factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.

Disaggregation of Revenue

Revenue is disaggregated by revenue source for our electric operations and by primary geographic markets for our coal operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors.

Electric operations


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Delivered energy (including contract liability amortization)	$	55,855	$	54,391	$	147,355	$	184,675
Capacity		15,860		13,012		44,506		46,137
Total Electric Operations sales	$	71,715	$	67,403	$	191,861	$	230,812

Coal operations


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Outside third-party Indiana customers	$	13,338	$	32,137	$	46,490	$	115,787
Customers in Florida, North Carolina, Alabama and Georgia		18,324		65,283		67,603		164,809
Total Coal Operations sales	$	31,662	$	97,420	$	114,093	$	280,596

Performance Obligations

Electric operations

We concluded that each megawatt-hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the customer.

During 2022, we entered into an Asset Purchase Agreement (“APA”) with Hoosier (“Hoosier APA”) in which Hallador Power shall sell, and Hoosier shall buy, delivered energy quantities through 2025 at the contract price, which is $34.00 per MWh. We have remaining delivered energy obligations to Hoosier on the APA totaling $70.1 million through 2025 as of September 30, 2024. The agreement was amended August 31, 2023, to extend through 2028. The amendment included additional obligations to Hoosier of $186.6 million, or $56.00 per MWh, as of September 30, 2024.

In addition to delivered energy, under the Hoosier APA, Hallador Power shall provide a stand-ready obligation to provide electricity to MISO, also known as contract capacity. The contract capacity that Hallador Power shall provide to Hoosier is 917 megawatts (“MW”) for contract year one, and on average 300 MW for contract years two to four. Hoosier shall pay Hallador Power the capacity price of $5.80 per kilowatt month for the contract capacity. We have remaining capacity obligations to Hoosier through 2025 totaling $25.0 million as of September 30, 2024. The agreement was amended August 31, 2023, to extend through 2028, with additional capacity obligations to Hoosier of $60.9 million as of September 30, 2024, at a price of $7.02 per kilowatt month for the contract capacity.

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During the second quarter 2024, the Company entered into an 11-month, $45.0 million prepaid physically delivered power contract in which Hallador will provide a total of 1,302,480 MWh. We have energy and capacity obligations to customers, excluding the Hoosier APA, through 2029 totaling $134.1 million and $140.2 million, respectively, as of September 30, 2024. We have $32.6 million and $24.7 million of deferred revenue as of September 30, 2024, related to the prepaid physically delivered power contract and other capacity obligations outside of the Hoosier APA, respectively.

Coal operations

A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.

We recognize revenue at a point in time as the customer does not have control over the asset at any point during the fulfillment of the contract. For substantially all our customers, this is supported by the fact that title and risk of loss transfer to the customer upon loading of the truck or railcar at the mine. This is also the point at which physical possession of the coal transfers to the customer, as well as the right to receive substantially all benefits and the risk of loss in ownership of the coal.

We have remaining coal sales performance obligations relating to fixed priced contracts to third-party customers of approximately $320.28 million, which represents the average fixed prices on our committed contracts as of September 30, 2024. We expect to recognize approximately 9.9% of this coal sales revenue in 2024, with the remainder recognized through 2028.

We have remaining volume performance obligations relating to coal contracts with price reopeners of 3.0 million tons (1.0 million tons in 2025, 2026 and 2027) as of September 30, 2024.

The coal tons used to determine the remaining performance obligations are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such an option exists in the customer contract.

Contract Balances

Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.

Under the typical payment terms of our contracts with customers, the customer pays us a base price for the coal, increased or decreased for any quality adjustments, electricity, or capacity. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our condensed consolidated balance sheets. As of January 1, 2023, accounts receivable for coal sales billed to customers was $16.3 million.

(8)	INCOME TAXES

For the nine months ended September 30, 2024 and 2023, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. The effective tax rate for the nine months ended September 30, 2024 and 2023, was ~24% and ~13%, respectively. Historically, our actual effective tax rates have differed from the statutory effective rate primarily due to the benefit received from statutory percentage depletion in excess of tax basis. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

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(9)	STOCK COMPENSATION PLANS


Non-vested grants as of December 31, 2023		858,363
Awarded - weighted average share price on award date was $5.69		599,013
Vested - weighted average share price on vested date was $5.30		(379,390)
Forfeited		(42,500)
Non-vested grants as of September 30, 2024		1,035,486

For the three and nine months ended September 30, 2024, our stock compensation was $1.1 million and $3.3 million, respectively. For the three and nine months ended September 30, 2023, our stock compensation was $0.8 million and $2.8 million, respectively.

Non-vested RSU grants will vest as follows:


Vesting Year		RSUs Vesting
2024		1,000
2025		682,068
2026		176,210
2027		176,208
		1,035,486

The outstanding RSUs have a value of $9.8 million based on the September 30, 2024 closing stock price of $9.43.

As of September 30, 2024, unrecognized stock compensation expense is $3.8 million, and we had 53,761 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities.

(10)

LEASES

We have operating leases for office space with remaining lease terms ranging from 1 month to 8 years. As most of the leases do not provide an implicit rate, we calculated the right-of-use assets and lease liabilities using our secured incremental borrowing rate at the lease commencement date. Imputed interest on our operating leases was $0.3 million as of September 30, 2024.

During the nine months ended September 30, 2024, we entered into four finance leases that were accounted for as failed sale-leaseback transactions. Finance lease assets are included in finance lease right-of-use assets on the condensed consolidated balance sheets and the associated finance lease liabilities are reflected within current portion of lease financing and long-term lease financing on the condensed consolidated balance sheets, as applicable. Depreciation on our finance lease assets was $1.5 million and $3.7 million for the three and nine months ended September 30, 2024. Interest expense on our finance lease liability was $0.4 million and $1.1 million during the three and nine months ended September 30, 2024, respectively. Imputed interest on our future remaining finance lease liability was $1.8 million as of September 30, 2024. We had deferred financing fees of $0.2 and $0.1 million at September 30, 2024 and December 31, 2023, respectively, in connection with entry into the finance leases. These deferred financing fees will be amortized on a straight-line basis over the term of the finance leases. We did not have finance leases during the three and nine months ended September 30, 2023.

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The following information relates to our leases (dollar amounts in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023
Operating lease information:
Operating cash outflows from operating leases	$	38		$	52		$	142		$	156
Weighted average remaining lease term in years		8.0			8.75			8.0			8.75
Weighted average discount rate		9.8	%		6.0	%		9.8	%		6.0	%
Finance lease information:
Financing cash outflows from finance leases	$	1,440			—		$	4,105			—
Proceeds from sale and leaseback arrangement	$	—			—		$	3,783			—
Weighted average remaining lease term in years		2.39			—			2.39			—
Weighted average discount rate		9.09	%		—			9.09	%		—

Future minimum lease payments under non-cancellable leases as of September 30, 2024, were as follows:


	Operating Leases		Finance Leases

	(In thousands)
2024	$	—	$	1,872
2025		108		7,490
2026		121		7,331
2027		125		749
2028		129		—
Thereafter		494		—
Total minimum lease payments	$	977	$	17,442
Less imputed interest and deferred finance fees		(320)		(1,960)
Total lease liability	$	657	$	15,482

The following are reflected within the indicated condensed consolidated balance sheet line items:


		For the Nine Months Ended September 30,		For the Year Ended December 31,
		2024		2023

		(In thousands)
Operating lease assets	Buildings and equipment	$	657	$	712
Operating lease liabilities:
Current operating lease liabilities	Accounts payable and accrued liabilities	$	-	$	58
Non-current operating lease liabilities	Other long-term liabilities		657		654
Total operating lease liability		$	657	$	712

Finance lease assets	Finance lease right-of-use assets	$	19,869	$	12,346
Finance lease liabilities:
Current finance lease liabilities	Current portion of lease financing	$	6,248	$	3,933
Non-current finance lease liabilities	Long-term lease financing		9,234		8,157
Total finance lease liabilities		$	15,482	$	12,090

(11)	SELF-INSURANCE

We self-insure our non-leased underground mining equipment. Such equipment was allocated among four mining units dispersed over seven miles and seven mining units dispersed over eleven miles, at September 30, 2024 and December 31, 2023, respectively. The historical cost of such equipment was approximately $247.3 million and $262.0 million as of September 30, 2024, and December 31, 2023.

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We also self-insure for workers’ compensation claims. Restricted cash of $5.8 million and $4.3 million as of September 30, 2024, and December 31, 2023, represents cash held and controlled by a third party and is restricted primarily for future workers’ compensation claim payments.

(12)	FAIR VALUE MEASUREMENTS

We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. We have no Level 2 instruments.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair value measures.

Credit Risk

The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.

The Company’s cash and cash equivalent and restricted cash balances on deposit with financial institutions total $9.6 million and $7.1 million as of September 30, 2024 and December 31, 2023, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. The Company utilizes large and reputable banking institutions which it believes mitigates these risks. The Company has not experienced any losses in such accounts.

(13)	EQUITY METHOD INVESTMENTS

We own a 50% interest in Sunrise Energy, LLC, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy, LLC, also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. The carrying value of the investment included in our condensed consolidated balance sheets as of September 30, 2024, and December 31, 2023, was $2.1 million and $2.8 million, respectively.

(14)	CONVERTIBLE NOTES

On July 29, 2022, we issued a $5.0 million senior unsecured convertible note (the “July 29^th Note”) to a related party affiliated with an independent member of our board of directors. The July 29^th Note carried an interest rate of 8% per annum with a maturity date of December 29, 2028. For the period August 18, 2022, through August 17, 2024, the holder had the option to convert the July 29^th Note into shares of the Company’s common stock at a conversion price of $6.254. During the first quarter of 2024, the holders of the July 29^th Note converted them into 799,488 shares of common stock of the Company, and in connection with such early conversion, we elected to pay interest through August 2025 with 112,570 shares of common stock on the conversion date. We recorded a loss on extinguishment of debt in the condensed consolidated statements of operations in the amount of $0.6 million during the three months ended March 31, 2024. As of September 30, 2024, the entire July 29^th Note had been converted to shares of common stock of the Company.

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On August 8, 2022, we issued an additional $4.0 million of senior unsecured convertible notes (the “August 8^th Notes”) to related parties affiliated with independent members of our board of directors. The August 8^th Notes carried an interest rate of 8% per annum with a maturity date of December 29, 2028. For the period August 18, 2022, through August 17, 2024, the holder had the option to convert the Notes into shares of the Company’s common stock at a conversion price of $6.254. Beginning August 8, 2025, we could elect to redeem the August 8^thNotes and the holder was obligated to surrender them at 100% of the outstanding principal balance together with any accrued unpaid interest. Upon receipt of the redemption notice from the Company, the holder could have elected to convert the principal balance and accrued interest into the Company’s common stock. During the first quarter of 2024, the holders converted $3.0 million of the August 8^th Notes into 479,693 shares of common stock of the Company, and in connection with such early conversion, we elected to pay interest through August 2025 with 67,542 shares of common stock on the conversion date. During the same period, the holders also converted accrued interest into 57,564 shares of the Company’s common stock. We recorded a loss on extinguishment of debt during the first quarter of 2024 in the condensed consolidated statements of operations in the amount of $0.3 million. During the second quarter of 2024, the holder converted the remaining $1.0 million of August 8^th Notes into 159,898 shares of common stock of the Company, and in connection with such early conversion, we paid accrued interest and additional shares of common stock of 5,099 and 25,003, respectively, on the conversion date. We recorded a loss on extinguishment of debt during the second quarter of 2024 in the condensed consolidated statements of operations in the amount of $0.2 million. As of September 30, 2024, the entire August 8^th Note had been converted to shares of common stock of the Company.

On August 12, 2022, we issued an additional $10.0 million senior unsecured convertible note (the “August 12^th Note”) to an unrelated party. The August 12^th Note carried an interest rate of 8% per annum with a maturity date of December 31, 2026. For the period August 18, 2022, through the maturity date, the holder had the option to convert the August 12^th Note into shares of the Company’s common stock at a conversion price of $6.15. Beginning August 12, 2025, we could elect to redeem the August 12^th Note and the holder would have been obligated to surrender at 100% of the outstanding principal balance together with any accrued unpaid interest. Upon receipt of the redemption notice from the Company, the holder could elect to convert the principal balance and accrued interest into the Company’s common stock. During the three months ended March 31, 2024, the holder converted accrued interest into 65,041 shares of the Company’s common stock. During the second quarter of 2024, the holder converted the $10.0 million August 12^th Note into 1,626,016 shares of common stock of the Company, and in connection with such early conversion, we paid accrued interest and additional shares of common stock of 49,716 and 224,268, respectively, on the conversion date. We recorded a loss on extinguishment of debt in the condensed consolidated statements of operations in the amount of $1.7 million during the second quarter of 2024. As of September 30, 2024, the entire August 12^th Note had been converted to shares of common stock of the Company.

The funds received from the issuance of the various notes described above were used to provide additional working capital to the Company. The conversion price and number of shares of the Company’s common stock issuable upon conversion of the above notes are subject to adjustment from time to time for any subdivision or consolidation of our shares of common stock and other standard dilutive events.

(15)	NOTES PAYABLE - RELATED PARTIES

In March 2024, we issued unsecured promissory notes, having a 12-month maturity date and 12% per annum interest rate, to (i) Charles R. Wesley IV Revocable Trust (in which our director Charles R. Wesley IV has a pecuniary interest) in the principal amount of $2,000,000, (ii) Lubar Opportunities Fund I, LLC (in which are our director David J. Lubar has a pecuniary interest) in the principal amount of $2,500,000, and (iii) Hallador Alternative Investment Advisors LLC (in which our director David C. Hardie has a pecuniary interest) in the principal amount of $500,000. The related party notes were paid off in June 2024 with proceeds from the prepaid physically delivered power contract mentioned above in “Note 7 – Revenue”.

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(16)	ORGANIZATIONAL RESTRUCTURING

On February 23, 2024, (the “Effective Date”), we committed to a reorganization effort in the Coal Operations Segment (the “Reorganization Plan”) that included a workforce reduction of approximately 110 employees, or approximately 12% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Reorganization Plan is designed to strengthen our financial and operational efficiency and create significant operational savings and higher margins in our coal segment. This step will help to advance our transition from a company primarily focused on coal production to a more resilient and diversified integrated independent power producer (“IPP”). As part of this initiative, we substantially idled production at our higher cost surface mines, Prosperity Mine, and Freelandville Mine, with minimal ongoing production. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. In connection with the Reorganization Plan, we incurred aggregate expenses of $1.9 million ($1.1 million in the first quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in operating expenses in the condensed consolidated statements of operations. These charges related to compensation, tax, professional, and insurance related expenses and are considered one-time charges paid in the nine months of 2024.

(17)	AT THE MARKET AGREEMENT

On December 18, 2023, we entered into an At The Market Issuance Sales Agreement (the “Sales Agreement”) with B. Riley Securities, Inc. (the “Agent”), pursuant to which we may issue and sell, from time to time, shares (the “Shares”) of our common stock, par value $0.01 per share (the “Common Stock”), with aggregate gross proceeds of up to $50.0 million through an “at-the-market” equity offering program under which the Agent will act as sales agent (the “ATM Program”). Under the Sales Agreement, we or the Agent have the right, by giving five (5) days’ notice, to terminate the Sales Agreement in our and the Agents sole discretion. The Agent may also terminate the Agreement, by notice to us, upon the occurrence of certain events described in the Sales Agreement.

During the nine months ended September 30, 2024, we issued 4,654,430 shares of Common Stock under the ATM Program for net proceeds of $34.5 million. No shares were issued under the ATM Program during the third quarter of 2024.

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(18)	SEGMENTS OF BUSINESS

As of September 30, 2024, our operations are divided into two primary reportable segments, Electric Operations and Coal Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, which the Company accounts for using the equity method and our held-for-sale wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

	(in thousands)				(in thousands)
Operating revenues
Electric operations⁽ⁱ⁾	$	71,902	$	67,544	$	192,379	$	231,141
Coal operations		49,331		134,896		162,630		343,267
Corporate and other and eliminations		(16,189)		(36,672)		(44,834)		(59,112)
Consolidated operating revenues	$	105,044	$	165,768	$	310,175	$	515,296

Operating expenses
Electric operations	$	52,547	$	70,220	$	150,989	$	205,856
Coal operations		61,510		110,132		197,587		279,052
Corporate and other and eliminations		(13,725)		(38,387)		(38,560)		(44,892)
Consolidated operating expenses	$	100,332	$	141,965	$	310,016	$	440,016

Income (loss) from operations
Electric operations	$	19,355	$	(2,676)	$	41,390	$	25,285
Coal operations		(12,179)		24,764		(34,957)		64,215
Corporate and other and eliminations		(2,464)		1,715		(6,274)		(14,220)
Consolidated income (loss) from operations	$	4,712	$	23,803	$	159	$	75,280

Depreciation, depletion and amortization
Electric operations	$	4,802	$	4,695	$	14,197	$	14,045
Coal operations		9,013		11,508		28,671		37,249
Corporate and other and eliminations		23		27		62		81
Consolidated depreciation, depletion and amortization	$	13,838	$	16,230	$	42,930	$	51,375

Assets
Electric operations	$	217,826	$	209,455	$	217,826	$	209,455
Coal operations		356,252		375,682		356,252		375,682
Corporate and other and eliminations		5,652		49		5,652		49
Consolidated assets	$	579,730	$	585,186	$	579,730	$	585,186

Capital expenditures
Electric operations	$	4,602	$	6,566	$	16,121	$	10,092
Coal operations		6,810		11,570		23,002		38,654
Corporate and other and eliminations		150		—		483		—
Consolidated capital expenditures	$	11,562	$	18,136	$	39,606	$	48,746

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(i).

Electric operations revenue as of each period presented were comprised of the components noted below (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Operating revenues:
Capacity revenue	$	15,860	$	13,012	$	44,506	$	46,137
Delivered energy		44,549		44,110		111,181		121,492
Amortization of contract liability		11,306		10,281		36,174		63,183
Other operating revenue		187		141		518		329
Total Electric Operations revenue:	$	71,902	$	67,544	$	192,379	$	231,141

(19)	NET INCOME (LOSS) PER SHARE

The following table (in thousands, except per share amounts) sets forth the computation of basic earnings (loss) per share for the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Basic earnings per common share:
Net income (loss) - basic	$	1,554	$	16,075	$	(10,346)	$	55,041
Weighted average shares outstanding - basic		42,598		33,140		38,455		33,088
Basic earnings (loss) per common share	$	0.04	$	0.49	$	(0.27)	$	1.66

The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Diluted earnings per common share:
Net income (loss) - basic	$	1,554	$	16,075	$	(10,346)	$	55,041
Add: Convertible Notes interest expense, net of tax		—		303		—		898
Net income (loss) - diluted	$	1,554	$	16,378	$	(10,346)	$	55,939

Weighted average shares outstanding - basic		42,598		33,140		38,455		33,088
Add: Dilutive effects of if converted Convertible Notes		—		3,162		—		3,164
Add: Dilutive effects of Restricted Stock Units		420		546		—		496
Weighted average shares outstanding - diluted		43,018		36,848		38,455		36,748

Diluted net income (loss) per share	$	0.04	$	0.44	$	(0.27)	$	1.52

(20)ASSETS HELD-FOR-SALE

During the third quarter of 2024, the Company considered strategic alternatives with respect to its wholly-owned subsidiary Summit. Summit is included in our “Corporate and other and eliminations” segment and primarily holds property, plant and equipment. On July 29, 2024, the Company entered into a ninety day right of first refusal (“ROFR”) with a potential buyer of Summit for $3.2 million. As of July 29, 2024 Summit met the held-for-sale criteria, and its assets are included in "assets held-for-sale" in the current assets section of the condensed consolidated balance sheets. The Company recorded the Summit assets, once held for sale, at the lower of their carrying value or their estimated fair value less cost to sell. The Company also did not record depreciation and amortization of $0.1 million ($0.1 million after-tax) on assets held-for-sale and will continue to do so while held-for-sale criteria is met. The Company expects the Summit sale to be executed by December 31, 2024.

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Fair value is the amount at which an asset, liability or business could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, or may be observable using quoted market prices. The Company used a market approach consisting of the contractual ROFR sales price, subject to prorations for property taxes and utilities, to determine the fair value as of September 30, 2024, and subtracted estimated costs to sell from that calculated fair value. The resulting net fair value of Summit's assets exceeded the carrying value of Summit’s assets, and accordingly no impairments were recorded.

The sale of Summit does not represent a strategic shift that has or will have a major effect on the Company, and as such, does not qualify for treatment as a discontinued operation.

(21)	SUBSEQUENT EVENTS

On October 23, 2024, the Company entered into a 19-month (beginning in June of 2025) $60.0 million prepaid physically delivered power contract in which Hallador will provide a total of 1,918,275 MWh. A portion of the proceeds were used to pay down $20.0 million on our Term Loan, which satisfies our January 2025, April 2025, July 2025 and a portion of our October 2025 required quarterly Term Loan payments. We also paid $34.0 million on our revolver.

On October 23, 2024, the Company entered into a second amendment to the Fourth Amended and Restated Credit Agreement with PNC, dated as of August 2, 2023, to clarify certain provisions of the First Amendment that was entered into on September 27, 2024.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2023 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.

Hallador Energy made significant progress in its transformation to an Independent Power Producer this quarter by signing a non-binding term sheet (“Term Sheet”) with a leading global data center developer. Our team is working diligently to finalize definitive agreements with this partner and relevant utilities that will support the delivery of our in front of the meter energy and capacity to the large hyperscaler. As we have discussed before, these types of deals are complex arrangements involving multiple parties. If we reach definitive agreements, we will have contracted large portions of our plant’s energy and capacity at much improved margins for more than a decade to come. The completion of the transaction contemplated by the Term Sheet is subject to, among other matters, the negotiation and execution of definitive agreements and there can be no assurance that definitive agreements will be entered into or that the proposed transaction will be consummated on the terms or timeframe currently contemplated, or at all.

The path to this type of long-term, higher margin transaction has been focused and deliberate. While we have not yet reached a binding agreement, we are encouraged both by the relationship with our current partner and the heavy interest that we continue to see from alternative counterparties in our energy and capacity offerings. This continued interest highlights the supply shortage in accredited capacity that we believe the MISO market is experiencing and provides the Company options in the event that we are unable to reach agreement in connection with the executed Term Sheet.

We believe accredited capacity in MISO continues to increase in value and demand, particularly in our sales region of MISO Zone 6, an area that includes Indiana and a portion of western Kentucky. This is important to Hallador based on our belief that Hallador has a significant amount of the remaining unsold accredited capacity in MISO Zone 6 over the next few years. Our current belief is guided by several factors, including:

●

Demand for power is growing at the fastest rate in several decades due to new demand from data centers, electric vehicles, and onshoring of industry.

●

Indiana is seeing consistent interest from data center developers, likely due to favorable Indiana tax law for datacenter development and a pro-business climate.

●

Supply Response is Restricted:

MISO has significantly reduced the capacity accreditation it awards to wind and solar generation (non-dispatchable), making it challenging to support accredited capacity needs from generating resources other than coal, U.S. natural gas (“Gas”), and nuclear (dispatchable).

We are currently seeing minimal supply response of accredited capacity which we believe relates to the regulatory and environmental challenges for all types of baseload generation, including Gas. Additionally, we believe the muted supply response is exacerbated by the glut of solar and wind projects, which provide minimal accredited capacity, overwhelming the queue and delaying access to dispatchable generation projects that would supplement the supply of accredited capacity.

●

While our data center PPA negotiations proceed, we continue to focus on improving our balance sheet and access to liquidity. During the quarter we modified our credit facility to provide the Company with short-term covenant relief to pursue additional liquidity. Subsequent to the quarter, we executed a prepaid forward power sale in the amount of $60.0 million (see “Item 1. Footnote 21 - Subsequent Events”), delivering power from June 2025 through December 2026. A portion of the proceeds were used to pay down $20.0 million on our Term Loan, which satisfies our January 2025, April 2025, July 2025 and a portion of our October 2025 required quarterly Term Loan payments. Our October 2025 required quarterly Term Loan payment is reduced to $6.0 million as part of the $20.0 million Term Loan pay down. We also paid $34.0 million on our revolver. We did not utilize the ATM in the third quarter.

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●

Quarter-over-Quarter our financial results improved. Our wholly owned subsidiary, Hallador Power, generated 1,074,000 MWh during the quarter versus 780,000 MWh in the second quarter of 2024. This is a result of stronger power pricing during the quarter and a significant decrease in Gas inventory levels against the imbalances we saw in the first half of the year. As Gas inventory decreased and prices increased, coal generation’s position in the dispatch stack improved. During the third quarter of 2024, our power plant operated more frequently than in the second quarter of 2024, partly due to having no planned maintenance, and as a result, our costs at the plant improved to $44.42 per MWh from $62.98 per MWh.

●

During the third quarter, results at our Sunrise Coal subsidiary also improved in connection with the restructuring of our mining division that we undertook beginning in the first quarter of 2024 (see “Item 1. Footnote 16 – Organizational Restructuring”). In July of 2024, we completed a project for four of our most productive units, which allowed all units to be on a split air system, which helped to improve efficiency and reduce operating costs at the mine to $66.43 per ton produced, a decrease of $1.59 from the second quarter of 2024. Sunrise Coal entered into a third-party coal contract to provide 2.5 million tons of coal from January 2026 to December 31, 2028, at an average price of $57.60 per ton.

Our goal is for Hallador Power to generate approximately 1,500,000 MWh on a quarterly basis, which equates to approximately 6,000,000 MWh annually (see Hallador Power’s capacity and utilization information below).  During the nine months ended September 30, 2024, Hallador Power generated 2,670,000 MWh, or 59.3% of our target. During the first nine months of the year, we experienced sales prices of nearly $261.00 per MWh for limited times, balanced against several days of pricing below our variable cost to produce. These fluctuations led to an inconsistent dispatch schedule.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Power Capacity and Utilization
Nameplate capacity (MW)⁽ⁱ⁾	1,080		1,080		1,080		1,080
Accredited capacity for the period (MW)⁽ⁱⁱ⁾	828		864		858		899
Accredited capacity utilization⁽ⁱⁱⁱ⁾	59.00	%	69.00	%	47.00	%	61.00	%

(i).

Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.

(ii).

Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 769 MW and 838 MW per day for 2024 and 2023, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.

(iii).

Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24 times the number of days for the period.

When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million. We have already sold a large portion of our near term Capacity, which we believe makes our forward Capacity sales goals attainable as illustrated in our “Solid Forward Sales Position” table below.

In addition to the Term Sheet discussed above, which is not included in the graph below, our forward contracted energy sales position has a significant price increase in future years as illustrated in the graph below.

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To match Sunrise’s production levels and cost structure to that of the market demands, we restructured Sunrise operations in the first quarter of 2024. As we have previously noted, the restructuring included a reduction in force (“RIF”) of approximately 110 people in February, and we have since allowed attrition to further reduce our workforce by approximately 140 additional people, a total workforce reduction of more than 25%. We also restructured our operations to focus on our more profitable units and to idle units with higher production costs. Transitioning our Oaktown mining facilities from 7 units of production to 4 units of production was a deliberate process which took considerable time and effort, and was completed in mid-July. We are encouraged by the early results of Sunrise’s restructuring and have seen improvement in mining costs since we made the decision to adjust our operations.

The Company last reviewed its long-lived assets for impairment during the fourth quarter of 2023 and concluded no impairment was indicated. In preparing the Company’s impairment analysis, it utilizes undiscounted net cash flows over the expected life of the long-lived asset based upon anticipated production along with contracted and forward prices as well as historical operating expenses adjusted for inflation. This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the Company and its Board of Directors no less than annually, normally during the fourth quarter of each year. Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.

During the third quarter of 2024, the Company began a review of our mining assets and our future mining plans. This review will continue through the fourth quarter of 2024. Should the anticipated future mining activity be reduced, an impairment of our mining assets could occur. The amount of any such potential impairment, if any, is not currently estimable and will ultimately be based upon the finalized operating plans of the Company as approved by its Board of Directors, market driven pricing and cost trends, which are not known at this time. Nevertheless, the carrying amount of the Company’s mining assets is material to its condensed consolidated balance sheet at September 30, 2024 and any future impairment of such assets could therefore be material. The Company has concluded that no impairment exists as of September 30, 2024 as no triggering events have occurred during the period ended September 30, 2024.

Our condensed consolidated financial statements should be read in conjunction with this discussion. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.

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OVERVIEW

Q3 2024 Net Income of $1.6 million.

Electric Operations: During the third quarter of 2024, we sold 1,183,000 MWh representing a 41.0% increase in total MWh sold and a decrease of $10.31 in operating revenues per MWh from Q2 2024.

In Q3 2024, Electric Operations operating revenues were $71.9 million, or $60.78 per MWh, on a segment basis.

ii.

In Q3 2024, Electric Operations operating expenses were $52.5 million, or $44.42 per MWh, which represents a decrease of $18.56 per MWh from Q2 2024.

iii.

Q3 2024 Electric Operations income from operations was $16.36 per MWh, an increase of $8.25 from Q2 2024.

Coal Operations: During the third quarter of 2024, 0.9 million tons of coal were shipped on a segment basis during the quarter, with approximately 0.3 million tons of that being shipped to the Merom Power Plant for $16.7 million. This is an increase of 0.1 million tons of coal shipped from Q2 2024, on a segment basis.

In Q3 2024, Coal Operations operating revenues were $49.3 million, or $53.27 per ton, on a segment basis.

ii.

In Q3 2024, Hallador’s Coal Operations operating expenses were $66.43 per ton on a segment basis, which represents a $1.59 per ton decrease from Q2 2024.

iii.

We recorded a loss from operations for the quarter of $13.16 per ton on a segment basis. This is a decrease in our loss of $0.17 per ton from Q2 2024 income from operations.

II.

Q3 2024 Activity

Cash Flow & Debt

During Q3 2024, we had net cash used in operating activities of $12.9 million, and we increased our bank debt by $24.5 million.

ii.

During the third quarter of 2024, we executed the First Amendment to our Credit Agreement. The primary purpose of the First Amendment was to provide us with short-term covenant relief to pursue additional liquidity. As of September 30, 2024, our bank debt was $70.0 million and our total liquidity was $34.9 million. Total liquidity is comprised of a) our additional borrowing capacity which is net of outstanding letters of credit that we are required to maintain for surety bonds and amounts drawn on our revolver, and b) cash and cash equivalents. See “Item 1. Footnote 5 – Bank Debt”.

iii.

During Q3 2024, we signed a ninety-day ROFR with a potential buyer of our wholly-owned subsidiary Summit for $3.2 million. Summit is included in our “Corporate and other and eliminations” segment and primarily holds property, plant and equipment. Summit met the held-for-sale criteria and its assets were included in “assets held-for-sale” in our current assets section of our condensed consolidated balance sheets. See “Item 1. Footnote 20 – Assets Held-For-Sale”.

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III.

Solid Forward Sales Position (unaudited)


	2024		2025		2026		2027		2028		2029		Total
Power
Energy
Contracted MWh (in millions)		0.81		2.56		1.83		1.78		1.09		0.27		8.34
Average contracted price per MWh	$	35.51	$	35.81	$	55.37	$	54.65	$	53.07	$	51.33
Contracted revenue (in millions)	$	28.76	$	91.67	$	101.33	$	97.28	$	57.85	$	13.86	$	390.75

Capacity
Average daily contracted capacity MW		716		801		744		623		454		100
Average contracted capacity price per MW	$	205	$	198	$	230	$	226	$	225	$	230
Contracted capacity revenue (in millions)	$	13.54	$	57.89	$	62.46	$	51.39	$	37.39	$	3.47	$	226.14

Total Energy & Capacity Revenue

Contracted Power revenue (in millions)	$	42.30	$	149.56	$	163.79	$	148.67	$	95.24	$	17.33	$	616.89

Coal
Priced tons - 3rd party (in millions)		0.66		1.78		1.50		1.50		0.50		—		5.94
Avg price per ton - 3rd party	$	48.02	$	50.04	$	56.17	$	57.17	$	59.00	$	—
Contracted coal revenue - 3rd party (in millions)	$	31.69	$	89.07	$	84.26	$	85.76	$	29.50	$	—	$	320.28

Committed and unpriced tons - 3rd party (in millions)		—		1		1		1		—		—		3

Total contracted tons - 3rd party (in millions)		0.66		2.78		2.50		2.50		0.50		—		8.94

TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED	$	73.99	$	238.63	$	248.05	$	234.43	$	124.74	$	17.33	$	937.17

Priced tons - Merom (in millions)		0.27		2.30		2.30		2.30		2.30		—		9.47
Avg price per ton - Merom	$	51.00	$	51.00	$	51.00	$	51.00	$	51.00	$	—
Contracted coal revenue - Merom (in millions)	$	13.77	$	117.30	$	117.30	$	117.30	$	117.30	$	—	$	482.97

TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT	$	87.76	$	355.93	$	365.35	$	351.73	$	242.04	$	17.33	$	1,420.14

●

Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $27.0 million and $79.5 million for the nine months ended September 30, 2024 and 2023, respectively.

Bank debt was reduced by $21.5 million during the nine months ended September 30, 2024. As of September 30, 2024, our bank debt was $70.0 million.

We expect cash generated from operations to primarily fund our capital expenditures and our debt service. As of September 30, 2024, we also had an additional borrowing capacity of $31.1 million.

Total liquidity as of September 30, 2024 was $34.9 million.

II.

Material Off-Balance Sheet Arrangements

Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value of reclamation obligations of $17.1 million, including $5.6 million at Merom, presented as asset retirement obligations (“ARO”) and accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.8 million to cover ARO.

CAPITAL EXPENDITURES (capex)

For the nine months ended September 30, 2024, capex was $39.6 million allocated as follows (in millions):


Oaktown – maintenance capex	$	18.3
Oaktown – investment		4.7
Freelandville Mine		—
Merom Plant		16.1
Other		0.5
Capex per the Condensed Consolidated Statements of Cash Flows	$	39.6

RESULTS OF OPERATIONS

Presentation of Segment Information

Our operations are divided into two primary reportable segments: Electric Operations and Coal Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the Notes to the Condensed Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method, and our held-for-sale wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

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Electric Operations


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

	(in thousands)				(in thousands)
Delivered Energy	$	55,855	$	54,391	$	147,355	$	184,675
Capacity		15,860		13,012		44,506		46,137
Other		187		141		518		329
OPERATING REVENUES:		71,902		67,544		192,379		231,141

EXPENSES:
Fuel		29,602		50,652		76,522		147,032
Other operating and maintenance costs		6,176		5,727		25,958		16,640
Cost of purchased power		3,149		—		7,694		—
Utilities		91		87		316		306
Labor		7,360		7,705		22,203		23,871
Depreciation, depletion and amortization		4,802		4,695		14,197		14,045
Asset retirement obligations accretion		115		159		339		468
Exploration costs		—		—		—		—
General and administrative		1,252		1,195		3,760		3,494
Total operating expenses		52,547		70,220		150,989		205,856
INCOME (LOSS) FROM OPERATIONS	$	19,355	$	(2,676)	$	41,390	$	25,285


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

	(per MWh Sold)				(per MWh Sold)
MWh Generated (in thousands)		1,074		1,307		2,670		3,612
MWh Purchased (in thousands)		109		—		243		—
MWh Sold (in thousands)		1,183		1,307		2,913		3,612

Delivered Energy	$	47.21	$	41.62	$	50.59	$	51.13
Capacity		13.41		9.96		15.28		12.77
Other		0.16		0.11		0.18		0.09
OPERATING REVENUES:		60.78		51.69		66.05		63.99

EXPENSES:
Fuel		25.02		38.75		26.27		40.71
Other operating and maintenance costs		5.22		4.38		8.91		4.61
Cost of purchased power		2.66		—		2.64		—
Utilities		0.08		0.07		0.11		0.08
Labor		6.22		5.90		7.62		6.61
Depreciation, depletion and amortization		4.06		3.59		4.87		3.89
Asset retirement obligations accretion		0.10		0.12		0.12		0.13
General and administrative		1.06		0.91		1.29		0.97
Total operating expenses		44.42		53.72		51.83		57.00
INCOME (LOSS) FROM OPERATIONS:	$	16.36	$	(2.03)	$	14.22	$	6.99

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2024 vs. 2023 (third quarter)

Revenues from electric operations increased $4.4 million, or 6.5%, compared to the third quarter of 2023. While the Merom Facility ran less hours in the third quarter of 2024 compared to 2023, the contracted hours were at higher prices. We have new delivered energy contracts and capacity contracts with sales starting in 2024. We entered into three new delivered energy contracts during the current year which increased revenues by $20.9 million. We entered into three capacity contracts during 2023 that began delivery in 2024 and one new capacity contract that we entered into during the current year, which increased revenues by $10.9 million. Revenue increases from new contracts were offset by suppressed MISO pricing (~66% of total energy hours at the Merom node being priced below our production cost at our Merom Facility), and reductions in demand for Power and higher demand for Gas as Gas inventories remained high, with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.59 during the same three-month period in 2023.

Fuel decreased $21.1 million, or 41.6%, compared to the third quarter of 2023. Our MWh sold decreased by 124 MWh, or 9.5%, from the third quarter of 2023. The decrease in fuel costs are primarily related to our decreased electricity sales and declines in coal market pricing. We used 0.1 million less tons of coal in our electric production compared to the third quarter of 2023. The average purchase price per ton of coal used in the plant on a segment basis, was $53.33 in the third quarter of 2024, decreasing from $76.94 per ton in the third quarter of 2023.

Cost of purchased power was $3.1 million during the third quarter of 2024. As noted above, when energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.

Income from operations increased $22.0 million, or 823.3%, and increased $18.39 per MWh, from the three months ended September 30, 2023. The main drivers of this change in income from operations are described in the discussion above.

2024 vs. 2023 (nine months)

Delivered energy revenues from electric operations decreased $37.3 million, or 20.2%, compared to the nine months ended September 30, 2023 due to suppressed MISO pricing (~75% of total energy hours at the Merom Hub being priced below our production cost at our Merom Facility), reductions in demand for Power and higher demand for Gas as Gas inventories remained high with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.47 during the same nine-month period in 2023.

Fuel decreased $70.5 million, or 48.0%, compared to the nine months ended September 30, 2023. Production decreased by 942 MWh, or 26.1%, from the first nine months of 2023. The decrease in fuel costs are due to the expiration of a coal purchase contract in June of 2023 and declines in coal market pricing. We used 0.5 million less tons of coal in our electric production compared to the nine months ended September 30, 2023. The average purchase price per ton of coal used in the plant on a segment basis, was $54.83 for the nine months ended September 30, 2024, decreasing from $62.37 during the nine months ended September 30, 2023. As discussed above, average spot prices for Gas were down per MMBtu decreasing the demand for Electric Power.

Cost of purchased power was $7.7 million during the first nine months of 2024. As noted above, when energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.

Other operating and maintenance costs increased $9.3 million, or 56.0%, compared to the nine months ended September 30, 2023 primarily due to our planned maintenance outage during the second quarter of 2024 which resulted in $7.0 million in additional costs for the period.

Income from operations increased $16.1 million, or 63.7%, and increased $7.23 per MWh, from the nine months ended September 30, 2023. The main drivers of this change in income from operations are described in the discussion above.

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Coal Operations


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

	(in thousands)				(in thousands)
OPERATING REVENUES:	$	49,331	$	134,896	$	162,630	$	343,267

EXPENSES:
Fuel		572		1,537		2,557		5,712
Other operating and maintenance costs		27,031		59,700		80,419		122,882
Utilities		3,094		4,421		10,639		13,041
Labor		19,361		29,934		66,241		90,827
Depreciation, depletion and amortization		9,013		11,508		28,671		37,249
Asset retirement obligations accretion		295		309		869		912
Exploration costs		62		171		179		682
General and administrative		2,082		2,552		8,012		7,747
Total operating expenses		61,510		110,132		197,587		279,052
INCOME (LOSS) FROM OPERATIONS	$	(12,179)	$	24,764	$	(34,957)	$	64,215


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

	(per ton)				(per ton)
Tons Sold (in thousands)		926		2,054		2,989		5,461

OPERATING REVENUES:	$	53.27	$	65.67	$	54.41	$	62.86

EXPENSES:
Fuel		0.62		0.75		0.86		1.05
Other operating and maintenance costs		29.19		29.07		26.90		22.50
Utilities		3.34		2.15		3.56		2.39
Labor		20.91		14.57		22.16		16.63
Depreciation, depletion and amortization		9.73		5.60		9.59		6.82
Asset retirement obligations accretion		0.32		0.15		0.29		0.17
Exploration costs		0.07		0.08		0.06		0.12
General and administrative		2.25		1.24		2.68		1.42
Total operating expenses		66.43		53.61		66.10		51.10
INCOME (LOSS) FROM OPERATIONS:	$	(13.16)	$	12.06	$	(11.69)	$	11.76

2024 vs. 2023 (third quarter)

Segment operating revenues from coal operations decreased $85.6 million, or 63.4%, from the third quarter of 2023. Consolidated operating revenues from coal operations decreased $65.2 million, or 66.6%, from the third quarter of 2023. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $12.40 per ton and we sold 1.1 million tons less compared to the third quarter of 2023. Our average sales price on a consolidated basis decreased $7.91 per ton and we sold 1.0 million tons less compared to the third quarter of 2023. Operating revenues for the third quarter of 2024 include $16.7 million in sales to the Merom plant which were eliminated in the consolidation.

Other operating and maintenance costs decreased $32.7 million, or 54.7%, and labor decreased $10.6 million, or 35.3%, from the third quarter of 2023. These changes were driven by impacts from the Reorganization Plan disclosed in “Item 1. Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements. During the third quarter 2024, underground costs such as roof support and belt maintenance, fuel and utilities, as well as maintenance costs all had significant decreases in comparison to the third quarter of 2023. We produced 0.7 million tons less in the third quarter of 2024 than the third quarter of 2023.

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Depreciation, depletion, and amortization decreased $2.5 million, or 21.7%, from the third quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $36.9 million, or 149.2%, and decreased $25.22 per ton, from the three months ended September 30, 2023. The main drivers of this change in income (loss) from operations are described in the discussion above.

2024 vs. 2023 (nine months)

Segment operating revenues from coal operations decreased $180.6 million, or 52.6%, from the nine months ended September 30, 2023. Consolidated operating revenues from coal operations decreased $166.0 million, or 58.7%, from the nine months ended September 30, 2023. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $8.45 per ton and we sold 2.5 million tons less compared to the first nine months of 2023. Our average sales price, on a consolidated basis, for the first nine months of 2024, decreased $4.63 per ton and we sold 2.6 million tons less compared to the first nine months of 2023.

Other operating and maintenance costs decreased $42.5 million, or 34.6%, and labor decreased $24.6 million, or 27.1%, from the nine months ended September 30, 2023. These changes were driven by the Reorganization Plan disclosed in “Item 1. Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements. During the first nine months of 2024, we produced 2.3 million tons less on a segment basis than the first nine months of 2023. Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 313 employees as part of the Reorganization Plan.

Depreciation, depletion, and amortization decreased $8.6 million, or 23.0%, from the nine months ended September 30, 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $99.2 million, or 154.4%, and decreased $23.45 per ton, from the nine months ended September 30, 2023. The main drivers of this change in income from operations are described in the discussion above.

Quarterly coal sales and cost data on a segment basis are as follows (in thousands, except per ton data and wash plant recovery percentage):


All Mines	4th 2023			1st 2024			2nd 2024			3rd 2024			T4Qs
Tons produced		1,331			1,271			889			873			4,364
Tons sold		1,461			1,214			849			926			4,450
Wash plant recovery in %		62	%		60	%		59	%		60	%
Capex	$	17,867		$	8,632		$	7,560		$	6,810		$	40,869
Maintenance capex	$	13,567		$	8,085		$	6,014		$	4,208		$	31,874
Maintenance capex per ton sold	$	9.29		$	6.66		$	7.08		$	4.54		$	7.16


All Mines	4th 2022			1st 2023			2nd 2023			3rd 2023			T4Qs
Tons produced		1,721			2,006			1,723			1,594			7,044
Tons sold		1,664			1,693			1,714			2,054			7,125
Wash plant recovery in %		68	%		70	%		67	%		65	%
Capex	$	12,368		$	12,639		$	14,445		$	11,570		$	51,022
Maintenance capex	$	5,748		$	7,778		$	9,754		$	7,938		$	31,218
Maintenance capex per ton	$	3.45		$	4.59		$	5.69		$	3.86		$	4.38

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Presentation of Consolidated Information

EARNINGS (LOSS) PER SHARE


	4th 2023		1st 2024		2nd 2024		3rd 2024
Basic	$	(0.31)	$	(0.05)	$	(0.27)	$	0.04
Diluted	$	(0.31)	$	(0.05)	$	(0.27)	$	0.04


	4th 2022		1st 2023		2nd 2023		3rd 2023
Basic	$	0.91	$	0.67	$	0.51	$	0.49
Diluted	$	0.83	$	0.61	$	0.47	$	0.44

INCOME TAXES

Our effective tax rate (ETR) is estimated at ~24% and ~13% for the nine months ended September 30, 2024 and 2023, respectively. For the nine months ended September 30, 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

RESTRICTED STOCK GRANTS

See “Item 1. Financial Statements - Note 9 - Stock Compensation Plans” for a discussion of RSUs.

CRITICAL ACCOUNTING ESTIMATES

We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, and the estimates used in impairment analysis are our critical accounting estimates.

The reserve estimates are used in the depreciation, depletion, and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal.

SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.

Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.

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Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant.

Inventory is valued at a lower of cost or net realizable value (NRV). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of September 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $1.8 million and $2.0 million, respectively.

Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the Company and its Board of Directors no less than annually, normally during the 4^th quarter of each year. Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.

During the third quarter of 2024, the Company began a review of its Oaktown mining facilities and future mining plan related to this complex. This review will continue through the fourth quarter of 2024. Should the anticipated future mining activity related to the Company’s Oaktown mining facilities be reduced, an impairment of certain mining assets could occur. The amount of any such potential impairment, if any, is not currently estimable and will ultimately be based upon the finalized operating plans of the Company as approved by its Board of Directors, market driven pricing and cost trends, which are not known at this time. Nevertheless, the carrying amount of the Company’s mining assets is material to its condensed consolidated balance sheet at September 30, 2024 and any future impairment of such assets could therefore be material.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

No material changes from the disclosure in our 2023 Annual Report on Form 10-K.

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ITEM 4. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS

We maintain a system of disclosure controls and procedures that are designed for the purpose of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our CEO and CFO and as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective.

There have been no changes to our internal control over financial reporting during the quarter ended September 30, 2024, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 4. MINE SAFETY DISCLOSURES

See Exhibit 95.1 to this Form 10-Q for a listing of our mine safety violations.

ITEM 6. EXHIBITS


Exhibit No.		Document
10.1		Fourth Amended and Restated Credit Agreement dated as of September 27, 2024 (incorporated by reference to Exhibit 10.1 of Current Report on Form 8-K filed by the Company on October 3, 2024)
10.2		Second Amended to the Fourth Amended and Restated Credit Agreement dated as of October 23, 2024
31.1		SOX 302 Certification - Chief Executive Officer
31.2		SOX 302 Certification - Chief Financial Officer
32		SOX 906 Certification
95.1		Mine Safety Disclosures
101.INS		Inline XBRL Instance Document
101.SCH		Inline XBRL Schema Document
101.CAL		Inline XBRL Calculation Linkbase Document
101.LAB		Inline XBRL Labels Linkbase Document
101.PRE		Inline XBRL Presentation Linkbase Document
101.DEF		Inline XBRL Definition Linkbase Document
104		Cover Page Interactive Data File (embedded with the Inline XBRL document)

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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.


	HALLADOR ENERGY COMPANY

Date: November 12, 2024	/s/ MARJORIE HARGRAVE
	Marjorie Hargrave, CFO (Principal Financial Officer and Principal Accounting Officer)

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Hallador Energy (HNRG) 10-Q2024 Q3 Quarterly report

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