PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Hallador Energy Company 

Condensed Consolidated Balance Sheets 

(in thousands, except per share data) 

(unaudited) 

 

    

See accompanying notes to the condensed consolidated financial statements.

Hallador Energy Company 

Condensed Consolidated Statements of Operations

(in thousands, except per share data) 

(unaudited) 

 

 

See accompanying notes to the condensed consolidated financial statements.

Hallador Energy Company 

Condensed Consolidated Statements of Cash Flows

(in thousands) 

(unaudited)

See accompanying notes to the condensed consolidated financial statements.

 Hallador Energy Company 

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands) 

(unaudited)

 

  

 

See accompanying notes to the condensed consolidated financial statements.

 

 

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. 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.

 

We strategically view and manage our operations through two 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, 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, a logistics transport facility located on the Ohio River.  

 

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 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 six months ended June 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. 

 

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 six-month periods ended June 30, 2024 and June 30, 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 June 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $0.9 million and $2.0 million, respectively.

 

(5)

BANK DEBT

 

At June 30, 2024, the Company had term debt of $45.5 million. 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.

 

Bank debt was reduced by $46.0 million during the six months ended June 30, 2024.

 

Liquidity

 

As of June 30, 2024, we had additional borrowing capacity of $54.4 million and total liquidity of $60.7 million. Our additional borrowing capacity utilizes our $75.0 million revolver availability and reduces it by $20.6 million for outstanding letters of credit that we were required to maintain for surety bonds.  Liquidity consists of our additional borrowing capacity and cash and cash equivalents.

 

Fees

 

Unamortized bank fees related to our term debt as of June 30, 2024, and December 31, 2023, were $2.8 million and $3.6 million, respectively.  These unamortized bank fees were deferred and are being amortized over the term of the loan.

 

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

 

		June 30,				December 31,
		2024				2023
Current bank debt		$	19,500			$	26,000
Less unamortized debt issuance cost			(1,562	)			(1,562	)
Net current portion		$	17,938			$	24,438
Long-term bank debt		$	26,000			$	65,500
Less unamortized debt issuance cost			(1,266	)			(2,047	)
Net long-term portion		$	24,734			$	63,453
Total bank debt		$	45,500			$	91,500
Less total unamortized debt issuance cost			(2,828	)			(3,609	)
Net bank debt		$	42,672			$	87,891

 

---

 

Covenants

 

The credit facility includes a Maximum Leverage Ratio (consolidated funded debt/trailing twelve months adjusted EBITDA), calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 2.25 to 1.00. As of June 30, 2024, our Leverage Ratio of 2.12 was in compliance with the requirements of the credit agreement.

 

The credit facility also requires a Minimum Debt Service Coverage Ratio (consolidated adjusted EBITDA/annual debt service) calculated as of the end of each fiscal quarter for the trailing twelve months of 1.25 to 1.00 through the credit facility's maturity. As of June 30, 2024, our Debt Service Coverage Ratio of 1.56 was in compliance with the requirements of the credit agreement.

 

As of June 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  June 30, 2024, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 10.49%.

 

Future Maturities (in thousands):
2024		$	6,500
2025			26,000
2026			13,000
Total		$	45,500

(6)	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

 

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

 

		June 30,				December 31,
		2024				2023
Accounts payable		$	29,151			$	43,636
Accrued property taxes			4,109				2,987
Accrued payroll			3,606				6,575
Workers' compensation reserve			4,364				3,629
Group health insurance			1,900				2,300
Asset retirement obligation - current portion			1,548				2,150
Other			1,212				1,631
Total accounts payable and accrued liabilities		$	45,890			$	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.

 

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 June 30,								Six Months Ended June 30,
		2024				2023				2024				2023
Delivered energy (including contract liability amortization)		$	39,973			$	53,862			$	86,955			$	130,284
Capacity			16,873				17,155				28,646				33,125
Total Electric Operations sales		$	56,846			$	71,017			$	115,601			$	163,409

 

Coal operations

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2024				2023				2024				2023
Outside third-party Indiana customers		$	15,048			$	34,214			$	33,152			$	83,650
Customers in Florida, North Carolina, Alabama and Georgia			17,753				54,360				49,279				99,526
Total Coal Operations sales		$	32,801			$	88,574			$	82,431			$	183,176

 

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 $83.9 million through 2025 as of June 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 June 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 $30.0 million as of June 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 June 30, 2024, at a price of $7.02 per kilowatt month for the contract capacity.

 

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 Hoosier, through 2029 totaling $152.0 million and $151.1 million, respectively, as of June 30, 2024. We have $45.0 million and $39.8 million of deferred revenue as of June 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 $207.7 million, which represents the average fixed prices on our committed contracts as of June 30, 2024. We expect to recognize approximately 30.3% of this coal sales revenue in 2024, with the remainder recognized through 2027.

 

We have remaining performance obligations relating to coal sales contracts with price reopeners of approximately $154.5 million, which represents our estimate of the expected reopener price on committed contracts as of June 30, 2024. We expect to recognize all of this coal sales revenue 2025 through 2027.

 

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 six months ended June 30, 2024 and 2023, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income, forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate.  The effective tax rate for the six months ended June 30, 2024 and 2023, was ~23% and ~11%, 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.

  

---

 

(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			(37,500	)
Non-vested grants as of June 30, 2024			1,040,486

 

For the three and six months ended June 30, 2024 our stock compensation was $1.6 million and $2.2 million, respectively. For the three and six months ended June 30, 2023, our stock compensation was $0.8 million and $2.0 million, respectively.

 

Non-vested RSU grants will vest as follows:

 

Vesting Year		RSUs Vesting
2024		1,000
2025		641,144
2026		199,171
2027		199,171
			1,040,486

 

The outstanding RSUs have a value of $8.1 million based on the June 28, 2024 closing stock price of $7.77.

 

As of June 30, 2024, unrecognized stock compensation expense is $5.7 million, and we had 48,761 RSUs available for future issuance.  RSUs are not allocated earnings and losses as they are considered non-participating securities.

(10)

LEASES

 

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2024				2023				2024				2023
Operating lease information:
Operating cash outflows from operating leases		$	52			$	52			$	104			$	104
Weighted average remaining lease term in years			7.6				0.95				7.6				0.95
Weighted average discount rate			10.5	%			6.0	%			10.5	%			6.0	%
Finance lease information:
Financing cash outflows from finance leases		$	1,427				—			$	2,665				—
Proceeds from sale and leaseback arrangement		$	1,856				—			$	3,783				—
Weighted average remaining lease term in years			2.64				—				2.64				—
Weighted average discount rate			8.5	%			—				8.5	%			—

 

---

 

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

 

		Operating				Finance
		Leases				Leases
		(In thousands)
2024		$	8			$	3,745
2025			118				7,490
2026			122				7,177
2027			125				662
2028			129				—
Thereafter			483				—
Total minimum lease payments		$	985			$	19,074
Less imputed interest and deferred finance fees			(347	)			(2,171	)
Total lease liability		$	638			$	16,903

 

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

 

			For the Six Months Ended June 30,				For the Year Ended December 31,
			2024				2023
			(In thousands)
Operating lease assets	Buildings and equipment		$	638			$	712
Operating lease liabilities:
Current operating lease liabilities	Accounts payable and accrued liabilities		$	8			$	58
Non-current operating lease liabilities	Other long-term liabilities			630				654
Total operating lease liability			$	638			$	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		$	6,204			$	3,933
Non-current finance lease liabilities	Long-term lease financing			10,699				8,157
Total finance lease liabilities			$	16,903			$	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 June 30, 2024 and December 31, 2023, respectively. The historical cost of such equipment was approximately $250.4 million and $262.0 million as of June 30, 2024, and December 31, 2023.

 

We also self-insure for workers’ compensation claims.  Restricted cash of $4.3 million as of June 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 $10.7 million and $7.1 million as of June 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 June 30, 2024, and December 31, 2023, was $2.3 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 29th Note”) to a related party affiliated with an independent member of our board of directors.  The July 29th Note carries 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 has the option to convert the July 29th 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 29th 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 six months ended June 30, 2024.  As of June 30, 2024, the entire July 29th Note had been converted to shares of common stock of the Company.

 

On August 8, 2022, we issued an additional $4.0 million of senior unsecured convertible notes (the “August 8th Notes”) to related parties affiliated with independent members of our board of directors.  The August 8th Notes carry 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 has 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 may elect to redeem the August 8th Notes and the holder shall be 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 may elect 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 8th 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 8th 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 June 30, 2024, the entire August 8th 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 12th Note”) to an unrelated party.  The August 12th Note carries 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 has the option to convert the August 12th Note into shares of the Company's common stock at a conversion price of $6.15.  Beginning August 12, 2025, we may elect to redeem the August 12th Note and the holder shall be 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 may 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 12th 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 June 30, 2024, the entire August 12th 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".  

(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 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 first six months of 2024.

(17)	AT THE MARKET AGREEMENT

 

 

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 is on a strategic and deliberate path to transform our company and capture increased value from our products and services as we advance up the value chain by expanding our offerings from fuel production to wholesale electricity sales to powering the industrial end user. 

 

For many years, our Sunrise Coal subsidiary was our primary asset, producing fuel to sell to third-party customers. In the fourth quarter of 2022, we acquired the Merom Power Plant through our Hallador Power Company (“Hallador Power” or “HPC”) subsidiary enabling us the ability to convert the majority of our fuel production into wholesale electricity and capacity, which traditionally sells at higher margins than coal. As part of this process, we issued $29.0 million of convertible debt in 2022 to improve our capital position and facilitate the acquisition of the Merom Power Plant.  In 2022, $10.0 million of these convertible notes were converted to equity and the remaining balance was converted in the first half of 2024.

 

Looking at the wholesale electric sales we have made since the acquisition of the Merom Power Plant, along with the prices indicated by the forward power curves, we believe that HPC has the potential to achieve gross profit margins greater than the margins we have historically seen in coal sales.  In the first quarter of this year, our sales to third-party customers from electricity exceeded those of our sales from coal. In connection with this shift in company focus, we changed our SIC code from 1220 bituminous coal producer to 4911 electric services during the second quarter.

 

Additionally, in the first quarter of this year we announced the signing of a Memorandum of Understanding (“MOU”) with Hoosier Energy and WIN REMC that provides a pathway to facilitate sales of our electricity to industrial end users of power. As we continue to transform our product offerings from fuel to wholesale electricity, to supplying power to higher value end-users, we believe we can achieve increasingly higher gross profit margins.

 

The recent environment for spot electricity sales has been challenging. This past winter, record high U.S. natural gas (“Gas”) production ran into the ninth warmest winter on record according to National Oceanic and Atmospheric Administration.  The lack of winter heating demand caused Gas inventory levels to climb as much as 38% above the 5-year average.  As Gas prices adjusted downward to encourage the market to consume excess Gas inventory, wholesale electric (“Energy”) prices also declined.  In the first six months of 2024, approximately 90% of the off-peak Energy hours at the Merom Hub and approximately 60% of the total Energy hours at the Merom Hub priced below our production cost at our Merom facility.

 

Our goal is for Hallador Power to generate approximately 1.5 million MWh on a quarterly basis, which equates to approximately 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below).  During the first half of 2024, Hallador Power generated 1,596,000 MWh, or 53% of our target. During the first half 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 June 30,								Six Months Ended June 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)			911				917				874				917
Accredited capacity utilization(iii)			39	%			52	%			42	%			58	%

 

	(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 860 MW per day for 2024 and 2023, respectively. Accreditations are 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 future Capacity, which we believe makes our forward Capacity sales goals attainable as illustrated in our "Solid Forward Sales Position" table below.

 

Our forward contracted energy sales position has a significant price increase in future years as illustrated in the graph below.

 

 

Lower Energy prices negatively affected both HPC’s generation model and the dispatch rates of Sunrise Coal’s utility customers.  In response to dispatching less, those customers slowed coal shipments from Sunrise during the winter season and throughout the shoulder season this spring.   

OVERVIEW

 

I.

Q2 2024 Net Loss of $10.2 million.

 

a.

Electric Operations: During the second quarter of 2024, we sold 780,000 MWh representing a 4.4% decline in total MWh sold and an increase of $0.90 in operating revenues per MWh from Q1 2024. The decline in total MWh sold during Q2 2024 was driven by MISO pricing that was lower than our cost to produce for approximately two-thirds of the quarter, lower Electric Power demand due to a mild 2024 spring and summer and higher Gas utilization due to low Gas pricing.

 

i.

In Q2 2024, Electric Operations operating revenues were $57.0 million, or $73.10 per MWh, on a segment basis.

 

ii.

In Q2 2024, Electric Operations operating expenses per MWh were $64.39, which represents an increase of $10.88 per MWh from Q1 2024.

 

iii.

Q2 2024 Electric Operations income from operations was $8.71 per MWh, a decline of $9.98 from Q1 2024.

 

b.

Coal Operations: During the second quarter of 2024, 0.8 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 $13.0 million.  This is a decline of 0.4 million tons of coal shipped from Q1 2024, primarily due to decreased demand from a mild 2024 spring and summer and continued low Gas prices.

  

i.

In Q2 2024, Coal Operations operating revenues were $46.4 million, or $54.69 per ton, on a segment basis.

 

ii.

In Q2 2024, Hallador's Coal Operations operating expenses were $68.02 per ton on a segment basis, which represents a $3.50 per ton increase from Q1 2024.  While Coal Operations operating expenses decreased $20.6 million in the second quarter of 2024 compared to the first quarter, tons sold also decreased 365,000 tons, or 30.1%, causing a higher operating expense per ton amount.

 

iii.

We recorded a loss from operations for the quarter of $(13.33) per ton on a segment basis.  This is a decline of $(3.89) per ton from Q1 2024 income from operations. These declines were due primarily to the reduction in contract average sales prices and the reduction in demand for coal due to low Gas prices.

 

II.

Q2 2024 Activity

 

a.

Cash Flow & Debt

 

i.

During Q2 2024, our operating cash flow was $23.5 million, and we decreased our bank debt by $31.5 million.

 

ii.

As of June 30, 2024, our bank debt was $45.5 million, liquidity was $60.7 million, and our leverage ratio came in at 2.12X, within our covenant of 2.25X.

 

iii.

During Q2 2024, we entered into an 11-month, $45.0 million prepaid physically delivered power contract in which we will provide a total of 1,302,480 MW, as discussed in “Item 1. Footnote 7 – Revenue”.

 

iv.

During Q2 2024, we paid off the $5.0 million unsecured one-year notes from related parties affiliated with certain members of the Board of Directors that were issued during Q1 2024.

 

v.

Our ATM offering program raised $27.9 million through the issuance of 3.9 million shares of our common stock.

 

vi.

We converted our remaining $11.0 million of senior unsecured convertible notes, including accrued interest with 1,840,729 shares of our Company common stock. We also issued 249,271 shares of our Company’s common stock as additional value to the holders for converting.

 

III.

Solid Forward Sales Position (unaudited)

 

		2024				2025				2026				2027				2028				2029				Total
Power
Energy
Contracted MWh (in millions)			1.75				2.48				1.83				1.78				1.09				0.27				9.20
Average contracted price per MWh		$	36.22			$	35.70			$	55.37			$	54.65			$	52.98			$	51.00
Contracted revenue (in millions)		$	63.39			$	88.54			$	101.33			$	97.28			$	57.75			$	13.77			$	422.06
Capacity
Average daily contracted capacity MWh			772				801				744				623				454				100
Average contracted capacity price per MWd		$	207			$	198			$	230			$	226			$	225			$	230
Contracted capacity revenue (in millions)		$	29.40			$	57.89			$	62.46			$	51.39			$	37.39			$	3.47			$	242.00
Total Energy & Capacity Revenue
Contracted Power revenue (in millions)		$	92.79			$	146.43			$	163.79			$	148.67			$	95.14			$	17.24			$	664.06
Coal
Priced tons - 3rd party (in millions)			1.26				1.78				0.50				0.50				—				—				4.04
Avg price per ton - 3rd party		$	50.08			$	50.04			$	55.50			$	55.50			$	—			$	—
Contracted coal revenue - 3rd party (in millions)		$	63.10			$	89.07			$	27.75			$	27.75			$	—			$	—			$	207.67
Committed and unpriced tons - 3rd party (in millions)			—				1				1				1				—				—				3
Total contracted tons - 3rd party (in millions)			1.26				2.78				1.50				1.50				—				—				7.04
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED		$	155.89			$	235.50			$	191.54			$	176.42			$	95.14			$	17.24			$	871.73
Priced tons - Merom (in millions)			0.60				2.30				2.30				2.30				2.30				—				9.80
Avg price per ton - Merom		$	51.00			$	51.00			$	51.00			$	51.00			$	51.00			$	—
Contracted coal revenue - Merom (in millions)		$	30.60			$	117.30			$	117.30			$	117.30			$	117.30			$	—			$	499.80
TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT		$	186.49			$	352.80			$	308.84			$	293.72			$	212.44			$	17.24			$	1,371.53

 

LIQUIDITY AND CAPITAL RESOURCES

 

I.

Liquidity and Capital Resources

 

a.

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $39.9 million and $44.2 million for the six months ended June 30, 2024 and 2023, respectively.

 

b.

Our projected electric capital expenditure budget for the remainder of 2024 is $6.5 million.  Our projected coal operations capital expenditure budget for the remainder of 2024 is $8.8 million.

 

c.

We paid down bank debt of $46.0 million in the first half of 2024. As of June 30, 2024, our bank debt was $45.5 million.

 

d.

We expect cash from operations generated primarily to fund our capital expenditures and our debt service.  As of June 30, 2024, we also had an additional borrowing capacity of $54.4 million.

 

II.

Material Off-Balance Sheet Arrangements

 

a.

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 $16.9 million, including $5.5 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 first six months of 2024, capex was $28.0 million allocated as follows (in millions):

 

Oaktown – maintenance capex		$	14.1
Oaktown – investment			2.1
Freelandville Mine			—
Merom Plant			11.5
Other			0.3
Capex per the Condensed Consolidated Statements of Cash Flows		$	28.0

 

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 wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

 

Electric Operations

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2024				2023				2024				2023
		(in thousands)								(in thousands)
Delivered Energy		$	39,973			$	53,862			$	86,955			$	130,284
Capacity			16,873				17,155				28,646				33,125
Other			174				86				331				188
OPERATING REVENUES:			57,020				71,103				115,932				163,597
EXPENSES:
Fuel			22,485				42,972				46,920				96,380
Other operating and maintenance costs			14,183				5,439				19,782				10,913
Utilities			143				116				225				219
Labor			7,160				7,469				14,843				16,166
Depreciation, depletion and amortization			4,698				4,675				9,395				9,350
Asset retirement obligations accretion			113				156				224				309
General and administrative			1,450				1,020				2,508				2,299
Total operating expenses			50,232				61,847				93,897				135,636
INCOME FROM OPERATIONS		$	6,788			$	9,256			$	22,035			$	27,961

 

 

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2024				2023				2024				2023
		(per MWh)								(per MWh)
MWh Sold			780				1,043				1,596				2,305
Delivered Energy		$	51.25			$	51.64			$	54.48			$	56.52
Capacity			21.63				16.41				17.95				14.37
Other			0.22				0.08				0.21				0.08
OPERATING REVENUES:			73.10				68.13				72.64				70.97
EXPENSES:
Fuel			28.83				41.20				29.40				41.81
Other operating and maintenance costs			18.18				5.21				12.39				4.73
Utilities			0.18				0.11				0.14				0.10
Labor			9.18				7.16				9.30				7.01
Depreciation, depletion and amortization			6.02				4.48				5.89				4.06
Asset retirement obligations accretion			0.14				0.15				0.14				0.13
General and administrative			1.86				0.98				1.57				1.00
Total operating expenses			64.39				59.29				58.83				58.84
INCOME FROM OPERATIONS:		$	8.71			$	8.84			$	13.81			$	12.13

 

2024 vs. 2023 (second quarter)

Operating revenues from electric operations decreased $14.1 million, or 19.8%, compared to the second quarter of 2023 due to approximately 60% of total Energy hours at the Merom Hub being priced below our production cost at our Merom Facility, low Electric Power demand due to a mild 2024 spring and summer, and higher demand for Gas as Gas prices averaged $2.08 per MBtu during the second quarter of 2024 compared to $2.16 per MBtu during the second quarter of 2023.

 

Fuel decreased $20.5 million, or 47.7%, compared to the second quarter of 2023 due to lower coal usage and energy production as a result of weakened demand for electricity. Electric production decreased by 263,000 MWh, or 25.2%, from the second quarter of 2023. We were also able to acquire third-party coal at prices below our production costs for coal, further reducing our fuel expense during the quarter. 

 

Other operating and maintenance costs increased $8.7 million, or 160.8%, compared to the second quarter of 2023 primarily due to the planned maintenance outage which resulted in $6.8 million in additional costs for the period.

 

Income from operations decreased $2.5 million, or 26.7%, and decreased $0.13 per MWh, from the three months ended June 30, 2023. The main drivers of this change in income from operations are described in the discussion above.

 

2024 vs. 2023 (first six months)

Operating revenues from electric operations decreased $47.7 million, or 29.1%, compared to the first half of 2023 due to MISO pricing that was lower than our cost to produce at times during the period, low Power demand due to a mild 2024 spring and summer, and higher demand for Gas as Gas prices during the spring season of 2024 (March through May) averaged $1.74 per MBtu compared to $2.21 per MBtu in the spring season of 2023.

 

Fuel decreased $49.5 million, or 51.3%, compared to the first half of 2023 due to lower coal usage and production as a result of weakened demand. Production decreased by 709,000 MWh, or 30.8%, from the first six months of 2023. Gas average spot prices were down $0.30 per MMBtu decreasing the demand for Electric Power. 

 

Other operating and maintenance costs increased $8.9 million, or 81.3%, compared to the first half of 2023 primarily due to the planned maintenance outage which resulted in $6.6 million in additional costs for the period.

 

Income from operations decreased $5.9 million, or 21.2%, and increased $1.68 per MWh, from the six months ended June 30, 2023. The main drivers of this change in income from operations are described in the discussion above.

Coal Operations

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2024				2023				2024				2023
		(in thousands)								(in thousands)
OPERATING REVENUES:		$	46,429			$	113,098			$	113,299			$	208,371
EXPENSES:
Fuel			750				1,610				1,985				4,175
Other operating and maintenance costs			21,597				36,275				53,388				63,182
Utilities			3,253				4,226				7,545				8,620
Labor			19,395				29,059				46,880				60,893
Depreciation, depletion and amortization			8,930				12,466				19,658				25,741
Asset retirement obligations accretion			286				305				574				603
Exploration costs			47				305				117				511
General and administrative			3,492				2,489				5,930				5,195
Total operating expenses			57,750				86,735				136,077				168,920
INCOME (LOSS) FROM OPERATIONS		$	(11,321	)		$	26,363			$	(22,778	)		$	39,451

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2024				2023				2024				2023
		(per ton)								(per ton)
Tons Sold			849				1,714				2,063				3,407
OPERATING REVENUES:		$	54.69			$	65.98			$	54.92			$	61.16
EXPENSES:
Fuel			0.88				0.94				0.96				1.23
Other operating and maintenance costs			25.44				21.16				25.88				18.54
Utilities			3.83				2.47				3.66				2.53
Labor			22.84				16.95				22.72				17.87
Depreciation, depletion and amortization			10.52				7.27				9.53				7.56
Asset retirement obligations accretion			0.34				0.18				0.28				0.18
Exploration costs			0.06				0.18				0.06				0.15
General and administrative			4.11				1.45				2.87				1.52
Total operating expenses			68.02				50.60				65.96				49.58
INCOME (LOSS) FROM OPERATIONS:		$	(13.33	)		$	15.38			$	(11.04	)		$	11.58

 

2024 vs. 2023 (second quarter)

Segment operating revenues from coal operations decreased $66.7 million, or 58.9%, from the second quarter of 2023. Consolidated operating revenues from coal operations decreased $56.0 million, or 63%, from the second 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 $11.29 per ton and we sold 0.9 million tons less compared to the second quarter of 2023. Our average sales price on a consolidated basis decreased $7.21 per ton and we sold 0.8 million tons less compared to the second quarter of 2023. Operating revenues for the second quarter of 2024 include $12.9 million in sales to the Merom plant which were eliminated in the consolidation.

 

Other operating and maintenance costs decreased $14.7 million, or 40.5%, and labor decreased $9.7 million, or 33.3%, from the second quarter of 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 second quarter 2024, we produced 0.4 million tons less than first quarter 2024, we reduced production days from 7 days to 5 days and further reduced our coal employee headcount by 130 employees.

 

Depreciation, depletion, and amortization decreased $3.5 million, or 28.4%, from the second quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets. 

 

Income (loss) from operations decreased $37.7 million, or 142.9%, and decreased $28.71 per ton, from the three months ended June 30, 2023. The main drivers of this change in income (loss) from operations are described in the discussion above.

2024 vs. 2023 (first six months)

Segment operating revenues from coal operations decreased $95.1 million, or 45.6%, from the first half of 2023. Consolidated operating revenues from coal operations decreased $100.8 million, or 55%, from the first half 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 $6.24 per ton and we sold 1.3 million tons less compared to the first six months of 2023. Our average sales price, on a consolidated basis, for the six months ended 2024, decreased $3.11 per ton and we sold 1.6 million tons less compared to the first six months of 2023.

 

Other operating and maintenance costs decreased $9.8 million, or 15.5%, and labor decreased $14.0 million, or 23.0%, from the first six months of 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 six months of 2024, we produced 1.6 million tons less on a segment basis than first six months of 2023, we went from 5 mines producing to 2 mines producing and further reduced our coal employee headcount by 339 employees.

 

Depreciation, depletion, and amortization decreased $6.1 million, or 23.6%, from the first half of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

 

Income (loss) from operations decreased $62.2 million, or 157.7%, and decreased $22.62 per ton, from the six months ended June 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		3rd 2023				4th 2023				1st 2024				2nd 2024				T4Qs
Tons produced			1,594				1,331				1,271				889				5,085
Tons sold			2,054				1,461				1,214				849				5,578
Wash plant recovery in %			65	%			62	%			60	%			59	%
Capex		$	11,570			$	17,867			$	8,632			$	7,560			$	45,629
Maintenance capex		$	7,938			$	13,567			$	8,085			$	6,014			$	35,604
Maintenance capex per ton		$	3.86			$	9.29			$	6.66			$	7.08			$	6.38

 

All Mines		3rd 2022				4th 2022				1st 2023				2nd 2023				T4Qs
Tons produced			1,663				1,721				2,006				1,723				7,113
Tons sold			1,705				1,664				1,693				1,714				6,776
Wash plant recovery in %			69	%			68	%			70	%			67	%
Capex		$	15,096			$	12,368			$	12,639			$	14,445			$	54,548
Maintenance capex		$	6,625			$	5,748			$	7,778			$	9,754			$	29,905
Maintenance capex per ton		$	3.89			$	3.45			$	4.59			$	5.69			$	4.41

 

Presentation of Consolidated Information

 

EARNINGS (LOSS) PER SHARE

		3rd 2023				4th 2023				1st 2024				2nd 2024
Basic		$	0.49			$	(0.31	)		$	(0.05	)		$	(0.27	)
Diluted		$	0.44			$	(0.31	)		$	(0.05	)		$	(0.27	)

 

		3rd 2022				4th 2022				1st 2023				2nd 2023
Basic		$	0.05			$	0.91			$	0.67			$	0.51
Diluted		$	0.05			$	0.83			$	0.61			$	0.47

 

INCOME TAXES

 

Our effective tax rate (ETR) is estimated at ~23% and ~11% for the six months ended June 30, 2024, and 2023, respectively.  For the six months ended June 30, 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income, 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.

 

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 June 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $0.9 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. Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

 

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

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

 

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 June 30, 2024, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

 

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		Separation Agreement and General Release (Lawrence D. Martin)
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)

 

 

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: August 7, 2024		/s/ MARJORIE HARGRAVE
		Marjorie Hargrave, CFO (Principal Financial Officer and Principal Accounting Officer)