# EDGAR Filing Document

**Accession Number:** 0000788965
**File Stem:** 0001104659-26-056375
**Filing Date:** 2026-5
**Character Count:** 174529
**Document Hash:** 65af90409cb70017e5ee5e183ff68642
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001104659-26-056375.hdr.sgml**: 20260506

**ACCESSION NUMBER**: 0001104659-26-056375

**CONFORMED SUBMISSION TYPE**: 10-Q

**PUBLIC DOCUMENT COUNT**: 79

**CONFORMED PERIOD OF REPORT**: 20260331

**FILED AS OF DATE**: 20260506

**DATE AS OF CHANGE**: 20260506

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** HALLADOR ENERGY CO
- **CENTRAL INDEX KEY:** 0000788965
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 841014610
- **STATE OF INCORPORATION:** CO
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-Q
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-34743
- **FILM NUMBER:** 26949784

**BUSINESS ADDRESS:**
- **STREET 1:** 1183 EAST CANVASBACK DRIVE
- **CITY:** TERRE HAUTE
- **STATE:** IN
- **ZIP:** 47802
- **BUSINESS PHONE:** 303-839-5504

**MAIL ADDRESS:**
- **STREET 1:** 1183 EAST CANVASBACK DRIVE
- **CITY:** TERRE HAUTE
- **STATE:** IN
- **ZIP:** 47802

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** HALLADOR PETROLEUM CO
- **DATE OF NAME CHANGE:** 19920703

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** KIMBARK OIL & GAS CO /CO/
- **DATE OF NAME CHANGE:** 19900102

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** KIMBARK INC
- **DATE OF NAME CHANGE:** 19860624

?xml version='1.0' encoding='ASCII'? HALLADOR ENERGY CO_March 31, 2026

[**Table of Contents**](#TOC)

------

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 10-Q**

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

For the quarterly period ended March 31, 2026

OR

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

Commission file number: 001-34743

![Graphic](hnrg-20260331x10q001.jpg)

**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 May 4, 2026, we had 47,130,392 shares of common stock outstanding.

------

[**Table of Contents**](#TOC)

#### **TABLE OF CONTENTS**

---

| | |
|:---|:---|
| [**PART I - FINANCIAL INFORMATION**](#PARTIFINANCIALINFORMATION_637946) | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 1. FINANCIAL STATEMENTS (Unaudited)](#ITEM1FINANCIALSTATEMENTS_314946) | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[Condensed Consolidated Balance Sheets](#ConsolidatedBalanceSheets_756008) | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[Condensed Consolidated Statements of Operations](#StatementsofOperations_920295) | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[Condensed Consolidated Statements of Cash Flows](#StatementsofCashFlows_850133) | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[Condensed Consolidated Statements of Stockholders' Equity](#StockholdersEquity_274942) | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[Notes to Condensed Consolidated Financial Statements](#FinancialStatements_109295) | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS](#ITEM2MANAGEMENTSDISCUSSION_153192) | 19 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK](#ITEM3QUANTITATIVEANDQUALITATIVE) | 30 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 4. CONTROLS AND PROCEDURES](#ITEM4CONTROLS_404437) | 32 |
| [**PART II - OTHER INFORMATION**](#PARTIIOTHERINFORMATION) | 32 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 1. LEGAL PROCEEDINGS](#ITEM1LEGALPROCEEDINGS) | 32 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 1A. RISK FACTORS](#ITEM1ARISKFACTORS) | 32 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS](#ITEM2UNREGISTEREDSALESOFEQUITYSECURITIES) | 32 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 3. DEFAULTS UPON SENIOR SECURITIES](#ITEM3DEFAULTSUPONSENIORSECURITIES) | 32 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 4. MINE SAFETY DISCLOSURES](#ITEM3DEFAULTSUPONSENIORSECURITIES) | 32 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 5. OTHER INFORMATION](#ITEM5OTHERINFORMATION) | 33 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[ITEM 6. EXHIBITS](#ITEM6EXHIBITS_987481) | 33 |
| [**SIGNATURES**](#SIGNATURES_218095) | 34 |

---

[**Table of Contents**](#TOC)

#### PART I - FINANCIAL INFORMATION

#### ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company

**Condensed Consolidated Balance Sheets**

(in thousands, except per share data)

(unaudited)

---

| | | |
|:---|:---|:---|
|  | **March 31,** <br>**2026** | **December 31,** <br>**2025** |
| **ASSETS** |  |  |
| **Current assets:** |  |  |
| &nbsp;&nbsp;Cash and cash equivalents | $36778 | $10070 |
| &nbsp;&nbsp;Restricted cash | 6585 | 5302 |
| &nbsp;&nbsp;Accounts receivable | 9152 | 13989 |
| &nbsp;&nbsp;Inventory | 47164 | 42534 |
| &nbsp;&nbsp;Parts and supplies | 47893 | 45854 |
| &nbsp;&nbsp;Prepaid expenses | 1604 | 5638 |
| &nbsp;&nbsp;Other current assets | 1927 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Total current assets | 151103 | 123387 |
| **Property, plant and equipment:** |  |  |
| &nbsp;&nbsp;Land and mineral rights | 69952 | 69952 |
| &nbsp;&nbsp;Buildings and equipment | 440682 | 421037 |
| &nbsp;&nbsp;Mine development | 102302 | 102302 |
| &nbsp;&nbsp;Construction work in progress | 35788 | 39671 |
| &nbsp;&nbsp;Finance lease right-of-use assets | 12591 | 12591 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total property, plant and equipment | 661315 | 645553 |
| &nbsp;&nbsp;Less - accumulated depreciation, depletion and amortization | (376481) | (367775) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total property, plant and equipment, net | 284834 | 277778 |
| &nbsp;&nbsp;Equity method investments | 2528 | 2647 |
| &nbsp;&nbsp;Operating lease right-of-use assets | 2315 |  |
| &nbsp;&nbsp;Other noncurrent assets | 7852 | 4241 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total assets** | $448632 | $408053 |
| **LIABILITIES AND STOCKHOLDERS' EQUITY** |  |  |
| **Current liabilities:** |  |  |
| &nbsp;&nbsp;Accounts payable | $19818 | $12594 |
| &nbsp;&nbsp;Accrued liabilities and other | 35078 | 29254 |
| &nbsp;&nbsp;Current portion of lease financing | 4981 | 7411 |
| &nbsp;&nbsp;Contract liabilities - current | 130170 | 103343 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total current liabilities | 190047 | 152602 |
| **Long-term liabilities:** |  |  |
| &nbsp;&nbsp;Bank debt, net |  | 29678 |
| &nbsp;&nbsp;Long-term lease financing | 617 | 1338 |
| &nbsp;&nbsp;Deferred income taxes | 1329 | 1833 |
| &nbsp;&nbsp;Asset retirement obligations | 15649 | 15241 |
| &nbsp;&nbsp;Contract liabilities - long-term | 32148 | 45714 |
| &nbsp;&nbsp;Other | 3268 | 1814 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total long-term liabilities | 53011 | 95618 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total liabilities | 243058 | 248220 |
| **Commitments and contingencies (Note 14)** |  |  |
| **Stockholders' equity:** |  |  |
| &nbsp;&nbsp;Preferred stock, $.10 par value, 10,000 shares authorized; none issued |  |  |
| &nbsp;&nbsp;Common stock, $.01 par value, 100,000 shares authorized; 47,132 and 43,817 issued and outstanding, as of March 31, 2026 and December 31, 2025, respectively | 471 | 438 |
| &nbsp;&nbsp;Additional paid-in capital | 257992 | 202963 |
| &nbsp;&nbsp;Retained deficit | (52889) | (43568) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total stockholders' equity | 205574 | 159833 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total liabilities and stockholders' equity** | $448632 | $408053 |

---

See accompanying notes to the condensed consolidated financial statements.

[**Table of Contents**](#TOC)

Hallador Energy Company

**Condensed Consolidated Statements of Operations**

(in thousands, except per share data)

(unaudited)

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
| **SALES AND OPERATING REVENUES:** |  |  |
| &nbsp;&nbsp;Electric sales | $65096 | $85943 |
| &nbsp;&nbsp;Coal sales | 35080 | 30185 |
| &nbsp;&nbsp;Other revenues | 1631 | 1596 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total sales and operating revenues | 101807 | 117724 |
| **EXPENSES:** |  |  |
| &nbsp;&nbsp;Fuel | 14963 | 15210 |
| &nbsp;&nbsp;Other operating and maintenance costs | 29156 | 28389 |
| &nbsp;&nbsp;Cost of purchased power | 14863 | 6840 |
| &nbsp;&nbsp;Utilities | 3333 | 4152 |
| &nbsp;&nbsp;Labor | 27388 | 27029 |
| &nbsp;&nbsp;Depreciation, depletion and amortization | 10606 | 14977 |
| &nbsp;&nbsp;Asset retirement obligations accretion | 408 | 427 |
| &nbsp;&nbsp;Exploration costs | 84 | 21 |
| &nbsp;&nbsp;General and administrative | 6858 | 6825 |
| &nbsp;&nbsp;Gain on disposal or abandonment of assets, net | (201) | (21) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total operating expenses | 107458 | 103849 |
| **INCOME (LOSS) FROM OPERATIONS** | (5651) | 13875 |
| &nbsp;&nbsp;Interest income | 147 | 63 |
| &nbsp;&nbsp;Interest expense (1) | (3970) | (3723) |
| &nbsp;&nbsp;Loss on extinguishment of debt | (230) |  |
| &nbsp;&nbsp;Equity method investment (loss) | (121) | (236) |
| **NET INCOME (LOSS) BEFORE INCOME TAXES** | (9825) | 9979 |
| **INCOME TAX EXPENSE (BENEFIT):** |  |  |
| &nbsp;&nbsp;Current |  |  |
| &nbsp;&nbsp;Deferred | (504) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Total income tax expense (benefit) | (504) |  |
| **NET INCOME (LOSS)** | $(9321) | $9979 |
| **NET INCOME (LOSS) PER SHARE:** |  |  |
| &nbsp;&nbsp;Basic | $(0.20) | $0.23 |
| &nbsp;&nbsp;Diluted | $(0.20) | $0.23 |
| **WEIGHTED AVERAGE SHARES OUTSTANDING** |  |  |
| &nbsp;&nbsp;Basic | 46519 | 42619 |
| &nbsp;&nbsp;Diluted | 46519 | 43462 |
| (1) Interest Expense: |  |  |
| Interest on bank debt | $862 | $1494 |
| Other interest | 2834 | 1732 |
| Amortization of debt issuance costs | 274 | 497 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total interest expense | $3970 | $3723 |

---

See accompanying notes to the condensed consolidated financial statements.

[**Table of Contents**](#TOC)

Hallador Energy Company

**Condensed Consolidated Statements of Cash Flows**

(in thousands)

(unaudited)

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
| **CASH FLOWS FROM OPERATING ACTIVITIES:** |  |  |
| Net income (loss) | $(9321) | $9979 |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |
| &nbsp;&nbsp;Deferred income tax (benefit) | (504) |  |
| &nbsp;&nbsp;Equity method investment loss | 121 | 236 |
| &nbsp;&nbsp;Depreciation, depletion and amortization | 10606 | 14977 |
| &nbsp;&nbsp;Gain on disposal or abandonment of assets, net | (201) | (21) |
| &nbsp;&nbsp;Loss on extinguishment of debt | 230 |  |
| &nbsp;&nbsp;Amortization of debt issuance costs | 274 | 497 |
| &nbsp;&nbsp;Asset retirement obligations accretion | 408 | 427 |
| &nbsp;&nbsp;Cash paid on asset retirement obligation reclamation | (148) | (156) |
| &nbsp;&nbsp;Stock-based compensation | 1135 | 1084 |
| &nbsp;&nbsp;Amortization of contract liabilities | (36447) | (35669) |
| &nbsp;&nbsp;Accretion on contract liabilities | 2834 | 1560 |
| &nbsp;&nbsp;Amortization of right-of-use assets | 87 |  |
| &nbsp;&nbsp;Other | 1533 | 3224 |
| &nbsp;&nbsp;Change in current assets and liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable | 4837 | 2856 |
| &nbsp;&nbsp;&nbsp;&nbsp;Inventory | (4630) | 367 |
| &nbsp;&nbsp;&nbsp;&nbsp;Parts and supplies | (2039) | (1033) |
| &nbsp;&nbsp;&nbsp;&nbsp;Prepaid expenses | (2580) | (330) |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts payable and accrued liabilities | 7427 | 3124 |
| &nbsp;&nbsp;&nbsp;&nbsp;Contract liabilities | 46874 | 37297 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net cash provided by operating activities | 20496 | 38419 |
| **CASH FLOWS FROM INVESTING ACTIVITIES:** |  |  |
| &nbsp;&nbsp;Capital expenditures | (7681) | (11693) |
| &nbsp;&nbsp;Proceeds from sale of equipment | 201 | 21 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net cash used in investing activities | (7480) | (11672) |
| **CASH FLOWS FROM FINANCING ACTIVITIES:** |  |  |
| &nbsp;&nbsp;Payments on bank debt | (56700) | (33000) |
| &nbsp;&nbsp;Borrowings of bank debt | 26700 | 12000 |
| &nbsp;&nbsp;Payments on lease financing | (3172) | (1693) |
| &nbsp;&nbsp;Debt issuance costs | (5780) |  |
| &nbsp;&nbsp;Proceeds from ATM offering, net of issuance costs | 201 |  |
| &nbsp;&nbsp;Proceeds from public offering, net of issuance costs | 53764 |  |
| &nbsp;&nbsp;Taxes paid on vesting of RSUs | (38) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net cash (used in) provided by financing activities | 14975 | (22693) |
| Increase in cash, cash equivalents, and restricted cash | 27991 | 4054 |
| Cash, cash equivalents, and restricted cash, beginning of period | 15372 | 12153 |
| Cash, cash equivalents, and restricted cash, end of period | $43363 | $16207 |
| **CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash and cash equivalents | $36778 | $6891 |
| &nbsp;&nbsp;&nbsp;&nbsp;Restricted cash | 6585 | 9316 |
|  | $43363 | $16207 |
| **SUPPLEMENTAL CASH FLOW INFORMATION:** |  |  |
| &nbsp;&nbsp;Cash paid for interest | $1002 | $1830 |
| &nbsp;&nbsp;Non-cash change in capital expenditures included in accounts payable and prepaid expense | $9981 | $(1649) |
| &nbsp;&nbsp;Right-of-use asset additions | $2402 | $— |

---

See accompanying notes to the condensed consolidated financial statements.

[**Table of Contents**](#TOC)

Hallador Energy Company

**Condensed Consolidated Statements of Stockholders' Equity**

(in thousands)

(unaudited)

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | **Common Stock Issued** | **Common Stock Issued** | | | |
|  | **Shares** | **Amount** | **Additional**<br>**Paid-in**<br>**Capital** | <br>**Retained**<br>**Deficit** | **Total**<br>**Stockholders'**<br>**Equity** |
| Balance, December 31, 2025 | 43817 | $438 | $202963 | $(43568) | $159833 |
| &nbsp;&nbsp;Stock-based compensation |  |  | 1135 |  | 1135 |
| &nbsp;&nbsp;Stock issued on vesting of RSUs | 191 | 2 | (40) |  | (38) |
| &nbsp;&nbsp;Taxes paid on vesting of RSUs | (81) | (1) | 1 |  |  |
| &nbsp;&nbsp;Stock issued in ATM offering | 11 |  | 201 |  | 201 |
| &nbsp;&nbsp;Stock issued in public offering  | 3194 | 32 | 53732 |  | 53764 |
| &nbsp;&nbsp;Net loss |  |  |  | (9321) | (9321) |
| Balance, March 31, 2026 | 47132 | $471 | $257992 | $(52889) | $205574 |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | **Common Stock Issued** | **Common Stock Issued** | | | |
|  | **Shares** | **Amount** | **Additional**<br>**Paid-in**<br>**Capital** | <br>**Retained**<br>**Deficit** | **Total**<br>**Stockholders'**<br>**Equity** |
| Balance, December 31, 2024 | 42621 | $426 | $189298 | $(85439) | $104285 |
| &nbsp;&nbsp;Stock-based compensation |  |  | 1084 |  | 1084 |
| &nbsp;&nbsp;Stock issued on vesting of RSUs | 513 | 5 | (5) |  |  |
| &nbsp;&nbsp;Taxes paid on vesting of RSUs | (156) | (1) | 1 |  |  |
| &nbsp;&nbsp;Net income |  |  |  | 9979 | 9979 |
| Balance, March 31, 2025 | 42978 | $430 | $190378 | $(75460) | $115348 |

---

See accompanying notes to the condensed consolidated financial statements.

[**Table of Contents**](#TOC)

Hallador Energy Company

**Notes to Condensed Consolidated Financial Statements**

(unaudited)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1) **BASIS OF PRESENTATION** 

Hallador Energy Company ("Hallador" or the "Company") is a vertically-integrated, independent power producer ("IPP") and fuel company with operations primarily in Indiana. The Company operates across multiple stages of the energy supply chain, from accredited capacity and electricity to coal. The Company's condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles ("GAAP"). The condensed consolidated financial statements include the accounts of Hallador and our wholly owned subsidiaries, including our main operating subsidiaries, Hallador Power Company, LLC ("Hallador Power") and Sunrise Coal, LLC ("Sunrise") and their respective subsidiaries, as well as Hourglass Sands, LLC. Additionally, we hold 50% interests in Sunrise Energy, LLC ("Sunrise Energy"), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC ("Oaktown Gas"), which we account for using the equity method. Our operations include Hallador Power which provides accredited capacity and energy to utilities and other energy market participants through the MISO interconnection, and Sunrise which mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States.

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.

Our unaudited condensed consolidated financial statements have been prepared in accordance with GAAP and with the instructions to Form 10-Q and Article 10 of Regulation S-X for interim financial information. Accordingly, these financial statements do not include all of the information required by GAAP or Securities and Exchange Commission ("SEC") rules and regulations for complete financial statements. In the opinion of management, these financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations for the interim periods presented. The results of operations for any interim period are not necessarily indicative of results for the full year. These unaudited condensed consolidated financial statements should be read in conjunction with our 2025 consolidated financial statements and notes thereto included in our 2025 Annual Report on Form 10-K (our "2025 10-K").

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Estimates and assumptions are used in accounting for, among other things, deferred income tax accounts, coal reserves, depreciation, depletion, and amortization, impairment analyses, and calculation of asset retirement obligations ("ARO"). Actual results could differ from those estimates.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2) **RECENT ACCOUNTING PRONOUNCEMENTS** 

**Recent Accounting Pronouncements - Adopted**

The Company has adopted Accounting Standards Update ("ASU") 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"), which is effective for fiscal years beginning after December 15, 2024. 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. Please see "*Note 7 – Income Taxes*" for additional information.

[**Table of Contents**](#TOC)

**Recent Accounting Pronouncements – Not Yet Adopted**

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting-Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses ("ASU 2024-03"). The update is intended to improve the disclosures about a public business entity's expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its financial statement disclosures.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3) **INVENTORY** 

Inventory is valued at the lower of cost or net realizable value ("NRV"). Coal inventory includes NRV adjustments of $0.1 million as of March 31, 2026, and December 31, 2025. During 2025, as part of the Company's routine inventory reconciliation process, a downward adjustment of $2.6 million was recorded to coal inventory.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4) **BANK DEBT** 

*New Credit Facility*

On March 5, 2026, Hallador entered into a credit agreement with Texas Capital Bank, as administrative agent, and Old National Bank, among others, that replaces the Credit Agreement with PNC Bank, National Association and includes a $75.0 million senior secured revolving credit facility (the "New Revolving Credit Facility") and a $45.0 million senior secured term loan facility (the "Delayed Draw Term Loan", and together with the New Revolving Credit Facility, the "New Credit Facility"). The New Revolving Credit Facility includes (i) a $25.0 million sub-facility for letters of credit and (ii) a $10.0 million sub-facility for swingline loans. The Company may, subject to conditions set forth in the New Credit Facility, request additional revolving facility commitments and incremental term loan commitments in an aggregate amount not to exceed $25.0 million. The Company and certain of its subsidiaries, as guarantors under the New Credit Facility, granted a security interest in substantially all of their assets to secure the Company's obligations under the New Credit Facility.

The New Credit Facility bears interest at a rate equal to, at the Company's election, either a base rate or term secured overnight financing rate ("SOFR"), plus an applicable margin based upon the Company's total leverage ratio. Under the New Credit Facility, (A) base rate loans will bear interest at a rate equal to the greater of (i) the prime rate, (ii) the sum of the Federal Funds Rate plus one half of one percent (0.50%), and (iii) the term SOFR plus one percent (1.00%), in each case, plus the applicable margin for base rate loans, which ranges from 2.25% to 2.75%, and (B) term SOFR loans will bear interest at term SOFR, plus the applicable margin for term SOFR loans, which ranges from 3.25% to 3.75%. The New Credit Facility includes a commitment fee of 0.50% on the daily unused portions of the New Revolving Credit Facility.

If the Delayed Draw Term Loan occurs, which is subject to meeting certain conditions, the principal balance of the Delayed Draw Term Loan shall be due and payable in equal quarterly installments of 2.5% of the original principal amount of such Delayed Draw Term Loan with a final payment of the remaining balance upon maturity. The New Credit Facility matures on March 5, 2029, and is collateralized by substantially all our assets. When drawn, the proceeds from the New Credit Facility may be used for ongoing working capital and general corporate purposes.

The Company used borrowings from the New Credit Facility, together with cash on hand to repay the Prior Credit Agreement (as defined below) in full. As of March 31, 2026, there were no outstanding borrowings under the New Revolving Credit Facility with $14.2 million in outstanding letters of credit. There was no Delayed Draw Term Loan balance outstanding at March 31, 2026.

[**Table of Contents**](#TOC)

*Prior Credit Agreement*

The Company was party to a credit agreement with PNC, in its capacity as administrative agent, which consisted of a revolving credit facility of up to $75.0 million and a term loan.

On June 27, 2025, the Company executed the Third Amendment ("Third Amendment") to our Credit Agreement, which was accounted for as a debt modification. The primary purpose of the Third Amendment was to provide additional operating flexibility for the remainder of 2025 by redefining covenants and deferring certain covenants until the third quarter of 2025. During the second quarter of 2025, the Company entered into a $35.0 million prepaid forward power sales contract of which $19.0 million of the proceeds were deposited into a money market account with the administrative agent as a compensating balance. The compensating balance was utilized to fully repay the outstanding term loan during the fourth quarter of 2025. As of March 5, 2026, the Company fully repaid its revolving credit facility.

#### Liquidity
Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents. As of March 31, 2026, we had additional borrowing capacity of $60.8 million under the New Revolving Credit Facility and total liquidity of $97.5 million. Our additional borrowing capacity is net of $14.2 million in outstanding letters of credit as of March 31, 2026 that were required to maintain surety bonds and other credit support obligations.

#### Fees
Bank fees and other costs incurred in connection with the New Credit Facility totaled $5.8 million and are reflected in other assets on the condensed consolidated balance sheets. These fees will be amortized over the term of the loan. Unamortized bank fees as of March 31, 2026, and December 31, 2025, were $5.6 million and $0.3 million, respectively. The New Credit Facility includes a commitment fee of 0.50% on any daily unused portions of the New Revolving Credit Facility.

Unamortized bank fees and other costs incurred in connection with our Prior Credit Agreement of $0.2 million were recorded as a loss on extinguishment of debt on the condensed consolidated statements of operations.

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

---

| | | |
|:---|:---|:---|
|  | **March 31,** <br>**2026** | **December 31,** <br>**2025** |
| Current bank debt | $— | $— |
| Less unamortized debt issuance cost (1) |  |  |
| &nbsp;&nbsp;Net current portion | $— | $— |
| Long-term bank debt | $— | $30000 |
| Less unamortized debt issuance cost (1) |  | (322) |
| &nbsp;&nbsp;Net long-term portion | $— | $29678 |
| Total bank debt | $— | $30000 |
| Less total unamortized debt issuance cost (1) |  | (322) |
| &nbsp;&nbsp;Net bank debt | $— | $29678 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1) Unamortized debt issuance costs of $1.9 million is included in other current assets and $3.7 million is included in other noncurrent assets on the condensed consolidated balance sheets as of March 31, 2026.

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#### Covenants
Prior to the date on which the conditions to availability of the Delayed Draw Term Loan are satisfied, our covenants include:

● Total leverage ratio – 2.50 to 1.00 stepping down to 2.25 to 1.00 in the fourth quarter 2026.

● Senior secured leverage ratio – 2.50 to 1.00 stepping down to 2.25 to 1.00 in the fourth quarter 2026.

● Minimum liquidity threshold – $20.0 million increasing to $25.0 million in the fourth quarter 2026.

● Fixed charge coverage ratio – 1.25 to 1.00.

After the conditions to availability of the Delayed Draw Term Loan are satisfied, our covenants will include:

● Total leverage ratio – 3.25 to 1.00 stepping down to 3.00 to 1.00 in the fourth quarter 2026.

● Senior secured leverage ratio – 2.00 to 1.00.

● Fixed charge coverage ratio – 1.25 to 1.00.

As of March 31, 2026, we were in compliance with all covenants defined in the New Credit Facility.

#### Interest Rate
The New Credit Facility bears interest with margins ranging from 2.25% to 3.75% above SOFR or the applicable base rate, subject to a SOFR floor of 1.00%, as further described above. The applicable margin is determined based upon the Company's leverage ratio and the type of loan drawn. As of March 31, 2026, we were subject to paying the applicable SOFR plus 3.50% on any outstanding bank debt which equates to an all-in rate of 7.16%.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5) **ACCRUED LIABILITIES AND OTHER** 

Accrued liabilities consist of the following for the indicated dates (in thousands):

---

| | | |
|:---|:---|:---|
|  | **March 31,** <br>**2026** | **December 31,** <br>**2025** |
| Accrued liabilities | 14320 | 10829 |
| Workers' compensation reserve | 4732 | 5223 |
| Accrued property taxes | 4474 | 3900 |
| Accrued payroll | 5076 | 3037 |
| ARO - current portion | 2460 | 2606 |
| Group heath insurance | 1350 | 1420 |
| Operating lease liability - current portion | 608 |  |
| Other | 2058 | 2239 |
| &nbsp;&nbsp;Total accrued liabilities and other | $35078 | $29254 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6) **REVENUE** 

#### Revenue from Contracts with Customers
We account for contracts with customers when the parties have executed 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

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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.

Under accredited capacity PPAs, we recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contracted accredited capacity performance obligations.

For delivered energy PPAs, we recognize revenue daily for the actual delivered MWh of electricity. For the prepaid delivered energy PPAs, we recognize revenue daily for the funds received for the actual delivered MWh of electricity plus any accretion attributable to the time value of money.

When there is an outage at one of the generating units at Merom or energy hours at the Merom Hub are priced below our production cost, we have the option to make net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power in our condensed consolidated statements of operations.

#### Coal operations
Our coal revenue is derived from sales to customers of coal produced at our mining facilities. Our customers typically purchase coal free on board from our mine sites where title, risk of loss, and control pass to the customer. 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. Coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, but some include a pre-determined escalation in price for each year and some allow for our customers to vary the fixed-volume by pre-determined quantities during a set period, such as quarterly. 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 typically contain coal quality specifications which require the raw coal sold by us to the customer to be (i) substantially free of magnetic material and other foreign material impurities and (ii) 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 British thermal unit factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped. When applicable, we have constrained the expected value of variable consideration in our estimation of transaction price and only included this consideration to the extent that it is probable that a significant revenue reversal will not occur.

#### 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

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| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
| Delivered energy (including contract liability amortization) | $49562 | $72136 |
| Accredited capacity | 15534 | 13807 |
| Total Electric Operations sales | $65096 | $85943 |

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#### Coal Operations

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
| Third party Indiana customers | $25913 | $20314 |
| Other customers | 9167 | 9871 |
| Total Coal Operations sales | $35080 | $30185 |

---

#### Performance Obligations
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.

**Electric Operations**

We concluded that each 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 accredited capacity provides an economic benefit to the holder and could be sold by the customer.

**Coal Operations**

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 using the base price per the contract, increased or decreased for quality adjustments.

**The following table illustrates the balance of all current Electric and Coal Operations contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of March 31, 2026 and disaggregated by segment and contract duration (in thousands).**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | **2026** | **2027** | **2028** | **2029** | **Total** |
| Delivered energy revenue | $135590 | $142290 | $57700 | $13860 | $349440 |
| Accredited capacity revenue | 52820 | 75260 | 73280 | 20440 | 221800 |
| Coal Operations revenue (1) | 117030 | 141850 | 29500 |  | 288380 |
| Total revenue  | $305440 | $359400 | $160480 | $34300 | $859620 |

---

(1) Coal Operations revenue consists of consolidated revenue excluding our intercompany revenues from Merom.

#### 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 the contracted price for electricity or accredited capacity. For coal contracts, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our condensed consolidated balance sheets. Payments received prior to fulfilling our performance obligations are included in contract liabilities in our condensed consolidated balance sheets. When the Company receives customer payments more than one year in advance of the related performance obligations, in accordance with ASC 606, the Company adjusts the transaction price for the significant financing component associated with these contracts at risk adjusted market rates. The resulting interest accretion is recognized as interest expense over the period between the customer payment date and the expected satisfaction of the performance obligation.

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The following table shows our beginning and ending accounts receivable balances from contracts with customers for the periods presented (in thousands):

---

| | | |
|:---|:---|:---|
|  | **March 31,** | **March 31,** |
|  | **2026** | **2025** |
| Accounts receivable from contracts with customers - beginning balance | $13989 | $15438 |
| Accounts receivable from contracts with customers - ending balance | $9152 | $12582 |

---

As the Company fulfills its contractual obligations, we recognized those amounts in revenue. The following table reconciles our beginning and ending contract liabilities for the periods presented (in thousands):

---

| | | |
|:---|:---|:---|
|  | **March 31,** | **March 31,** |
|  | **2026** | **2025** |
| Total contract liabilities - beginning balance | $149057 | $146719 |
| Cash payments received on future contract obligations | 46874 | 37297 |
| Accretion on contract liabilities | 2834 | 1560 |
| Revenue recognized, cash payment received in prior period | (36447) | (35669) |
| Total contract liabilities - ending balance | $162318 | $149907 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(7) **INCOME TAXES** 

For the three months ended March 31, 2026 and 2025, 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 three months ended March 31, 2026 and 2025, was approximately 5.2% and 0%, respectively, due to recording of a valuation allowance. Historically, our actual effective tax rates 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.

On July 4, 2025, H.R.1, commonly referred to as the One Big Beautiful Bill Act ("OBBBA") was enacted. The OBBBA includes a broad range of tax reform provisions affecting businesses, including extending and modifying certain key Tax Cuts & Jobs Act provisions (both domestic and international), expanding certain Inflation Reduction Act incentives, and accelerating the phase-out of or repealing others. We have analyzed the provisions within the act and determined that the benefits relating to capital expenditures and deductibility of interest under IRC Section 163(j) will provide cash flow benefits to the company by accelerating deductions for tax purposes. As the material benefits relate to the timing of deductions, there were no material impact affecting the effective tax rate or the valuation allowance determination in the period that OBBBA was enacted.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(8) **STOCK COMPENSATION PLANS** 

Non-vested grants and activity for the period presented are as follows (in whole shares):

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| | |
|:---|:---|
| Non-vested grants as of December 31, 2025 | 586101 |
| &nbsp;&nbsp;Awarded  | 9973 |
| &nbsp;&nbsp;Vested | (191307) |
| &nbsp;&nbsp;Forfeited |  |
| Non-vested grants as of March 31, 2026 | 404767 |

---

Stock compensation expense was $1.1 million for the three months ended March 31, 2026 and 2025.

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Non-vested restricted stock unit ("RSU") grants will vest as follows (in whole shares):

---

| | |
|:---|:---|
| **Vesting Year** | **RSUs Vesting** |
| 2026 | 15,872 |
| 2027 | 377,679 |
| 2028 | 11,216 |
|  | 404,767 |

---

As of March 31, 2026, unrecognized stock compensation expense to be recognized over the respective vesting period is $3.2 million, and we had 2,075,261 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities. Forfeitures are recognized as they occur.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(9) **SELF-INSURANCE** 

The Company is self-insured for certain risks, including physical damage and operational liability, related to our non-leased underground mining equipment. The Company records a liability for self-insured risks when a loss is both probable and reasonably estimable. The Company had no accrual for self-insurance liabilities as of March 31, 2026 or December 31, 2025.

The Company also self-insures for a portion of its workers' compensation claims under a guaranteed cost program. Under this program, the Company is responsible for the first $1.0 million per claim up to an aggregate of $4.0 million annually. As of March 31, 2026 and December 31, 2025 the Company has restricted cash of $3.3 million and $3.0 million as of March 31, 2026 and December 31, 2025, respectively, for future workers' compensation claim payments. The Company had $4.7 million and $5.2 million of workers' compensation reserve as of March 31, 2026 and December 31, 2025, respectively, in accrued liabilities on the condensed consolidated balance sheets.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(10) **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.

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*.*

The carrying amounts for cash equivalents, accounts receivable, accounts payable, accrued liabilities and other, approximate fair value due to the short maturity of those instruments. 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.

#### Credit Risk
The Company's financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.

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The Company's cash and cash equivalent and restricted cash balances on deposit with financial institutions total $43.4 million and $15.4 million as of March 31, 2026 and December 31, 2025, 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(11) **EQUITY METHOD INVESTMENTS** 

We own a 50% interest in Sunrise Energy which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy 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 was $1.9 million as of March 31, 2026 and December 31, 2025.

The Company also owns a 50% interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value of the investment included in the condensed consolidated balance sheets as of March 31, 2026 and December 31, 2025, was $0.6 million and $0.7 million, respectively.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(12) **SEGMENTS OF BUSINESS** 

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The CODM, who is the Company's Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.

Our Electric Operations segment includes the electric power generation facilities of our Merom power plant, which is a two-unit, 1080-megawatt rated coal fired power plant located in Sullivan County, Indiana. Our sales region is in MISO Zone 6, which includes Indiana and a portion of western Kentucky. Revenues from our Electric Operations segment consist primarily of delivered energy and accredited capacity revenues. Fuel costs included in our Electric Operations segment include the cost of coal purchased from our Coal Operations segment, which are based on multi-year contracts which approximate market prices at the time the contracts were agreed.

Our Coal Operations segment includes the Oaktown 1 underground mining complex, as well as other currently idled mining facilities, which produce high-quality bituminous coal from the Illinois Basin. Revenue from our Coal Operations segment consists of sales of coal to various third parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts that approximated market prices at the time the contracts were agreed. Intercompany coal sales and amounts above actual costs to produce the coal are eliminated in the condensed consolidated statements of operations.

In addition to these reportable segments, the Company has a "Corporate and Other and Eliminations" category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including our equity method investments.

The CODM evaluates segment performance based upon Segment EBITDA for each business segment. Segment EBITDA is calculated for each segment as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. For our Electric Operations segment, Segment EBITDA is comprised of accredited capacity and delivered energy revenues less certain significant segment expenses, which include (i) variable costs comprised of fuel costs and certain other operating costs, such as limestone and soda ash, (ii) other operating and maintenance costs, (iii) costs of purchased power, (iv) utilities, (v) labor and (vi) general and administrative costs .

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2. For our Coal Operations segment, Segment EBITDA is comprised of coal sales less certain significant segment expenses, which include (i) fuel, (ii) other operating and maintenance costs, (iii) utilities, (iv) labor and (v) general and administrative costs.

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Segment EBITDA for each segment is a key measure used by our CODM and provides information about our core operating performance, significant expenses and ability to generate cash flow. Additionally, Segment EBITDA provides investors with the financial analytical framework upon which our CODM bases financial, operational, compensation and planning decisions and presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations. Our CODM reviews variable costs, as defined above, in our Electric Operations segment in order to evaluate the efficiency of that segment's operations.

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended March 31, 2026 (in thousands):

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| | | | |
|:---|:---|:---|:---|
|  | **Electric Operations** |  | **Coal Operations** |
| Delivered energy | $49562 | Coal sales | $46412 |
| Accredited capacity revenue | 15534 |  |  |
| Electric sales | $65096 |  |  |
| Fuel | $(27527) |  |  |
| Other operating costs (1) | (29) |  |  |
| Total variable costs | $(27556) |  |  |
| Other operating and maintenance costs (2) | $(8854) | Fuel | $(528) |
| Cost of purchased power | (14863) | Other operating and maintenance costs | (20273) |
| Utilities | (134) | Utilities | (3199) |
| Labor | (8129) | Labor | (19259) |
| Power margin without general and administrative | 5560 | Coal margin without general and administrative | 3153 |
| General and administrative | (1310) | General and administrative | (2211) |
| Electric Operations — Segment EBITDA | $4250 | Coal Operations — Segment EBITDA  | $942 |

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(1) Other operating costs primarily include costs for lime dust. <br> (2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable included in fuel and other operating costs.

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended March 31, 2025 (in thousands):

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| | | | |
|:---|:---|:---|:---|
|  | **Electric Operations** |  | **Coal Operations** |
| Delivered energy | $72136 | Coal sales | $54774 |
| Accredited capacity revenue | 13807 |  |  |
| Electric sales | $85943 |  |  |
| Fuel | $(38071) |  |  |
| Other operating costs (1) | (8) |  |  |
| Total variable costs | $(38079) |  |  |
| Other operating and maintenance costs (2) | $(4527) | Fuel | $(556) |
| Cost of purchased power | (6840) | Other operating and maintenance costs | (23854) |
| Utilities | (676) | Utilities | (3476) |
| Labor | (8143) | Labor | (18886) |
| Power margin without general and administrative | 27678 | Coal margin without general and administrative | 8002 |
| General and administrative | (1535) | General and administrative | (2313) |
| Electric Operations — Segment EBITDA | $26143 | Coal Operations — Segment EBITDA  | $5689 |

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(1) Other operating costs primarily include costs for lime dust. <br> (2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable included in fuel and other operating costs.

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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended March 31, 2026 (in thousands):

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| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  | **Corporate and Other** |  |
| Reconciliation of Revenue: | **Electric Operations**  | **Coal Operations** | **and Eliminations** | **Consolidated** |
| Delivered energy | $49562 | $— | $— | $49562 |
| Accredited capacity revenue | 15534 |  |  | 15534 |
| Other operating revenue | 137 | 1140 | 354 | 1631 |
| Coal sales (third party) |  | 35080 |  | 35080 |
| Coal sales (intercompany) |  | 11332 | (11332) |  |
| Operating Revenue | $65233 | $47552 | $(10978) | $101807 |

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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended March 31, 2025 (in thousands):

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| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  | **Corporate and Other** |  |
| Reconciliation of Revenue: | **Electric Operations**  | **Coal Operations** | **and Eliminations** | **Consolidated** |
| Delivered energy | $72136 | $— | $— | $72136 |
| Accredited capacity revenue | 13807 |  |  | 13807 |
| Other operating revenue | 87 | 1261 | 248 | 1596 |
| Coal sales (third party) |  | 30185 |  | 30185 |
| Coal sales (intercompany) |  | 24589 | (24589) |  |
| Operating Revenue | $86030 | $56035 | $(24341) | $117724 |

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Presented below is our reconciliation of Segment EBITDA to the most comparable GAAP account, income (loss) before income taxes for the three months ended March 31, 2026 (in thousands):

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| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  | **Corporate and Other** |  |
| Reconciliation of Income (Loss) before Income Taxes: | **Electric Operations**  | **Coal Operations** | **and Eliminations** | **Consolidated** |
| Income (Loss) before Income Taxes | $(5038) | $(2979) | $(1808) | $(9825) |
| Other operating revenue | (137) | (1140) | (354) | (1631) |
| Depreciation, depletion and amortization | 6383 | 4204 | 19 | 10606 |
| ARO accretion | 131 | 277 |  | 408 |
| Exploration costs |  | 84 |  | 84 |
| (Gain) loss on disposal or abandonment of assets, net |  | (201) |  | (201) |
| Interest income | (36) | (111) |  | (147) |
| Interest expense | 2947 | 808 | 215 | 3970 |
| Loss on extinguishment of debt |  |  | 230 | 230 |
| Equity method investment (loss) |  |  | 121 | 121 |
| Corporate — general and administrative |  |  | 3337 | 3337 |
| Segment EBITDA | $4250 | $942 | $1760 | $6952 |

---

Presented below is our reconciliation of Segment EBITDA to the most comparable GAAP account, income (loss) before income taxes for the three months ended March 31, 2025 (in thousands):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  | **Corporate and Other** |  |
| Reconciliation of Income (Loss) before Income Taxes: | **Electric Operations**  | **Coal Operations** | **and Eliminations** | **Consolidated** |
| Income (Loss) before Income Taxes | $19217 | $(5082) | $(4156) | $9979 |
| Other operating revenue | (87) | (1261) | (248) | (1596) |
| Depreciation, depletion and amortization | 5161 | 9797 | 19 | 14977 |
| ARO accretion | 120 | 307 |  | 427 |
| Exploration costs |  | 21 |  | 21 |
| (Gain) loss on disposal or abandonment of assets, net |  | (21) |  | (21) |
| Interest income |  | (63) |  | (63) |
| Interest expense | 1732 | 1991 |  | 3723 |
| Equity method investment (loss) |  |  | 236 | 236 |
| Corporate — general and administrative |  |  | 2977 | 2977 |
| Segment EBITDA | $26143 | $5689 | $(1172) | $30660 |

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Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):

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| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  | **Corporate and Other** |  |
| Other Reconciliations: | **Electric Operations**  | **Coal Operations (1)** | **and Eliminations** | **Consolidated** |
| Assets at March 31, 2026 | $254332 | $184915 | $9385 | $448632 |
| Assets at December 31, 2025 | $256529 | $148957 | $2567 | $408053 |
| Capital Expenditures for the period ending March 31, 2026 | $3889 | $3792 | $— | $7681 |

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1) Coal Operations assets include cash held on behalf of the consolidated group. Cash held by our Coal Operations includes funds transferred from Electric Operations and Hallador for centralized treasury management purposes. This presentation is not reflective of Coal Operations earnings capacity; refer to the condensed consolidated balance sheets and the *"Liquidity of Hallador"* in the *"Material Changes in Financial Condition"* section of *"Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations"* for a complete view of the Company's cash position.

Cash and cash equivalents included in Coal Operations assets were $36.3 million and $9.4 million as of March 31, 2026 and December 31, 2025, respectively.

Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  | **Corporate and Other** |  |
| Other Reconciliations: | **Electric Operations**  | **Coal Operations (1)** | **and Eliminations** | **Consolidated** |
| Assets at March 31, 2025 | $222865 | $141023 | $2209 | $366097 |
| Assets at December 31, 2024 | $220477 | $144519 | $4124 | $369120 |
| Capital Expenditures for the period ending March 31, 2025 | $5449 | $6244 | $— | $11693 |

---

Cash and cash equivalents included in Coal Operations assets were $5.6 million and $6.9 million as of March 31, 2025 and December 31, 2024, respectively.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(13) **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 presented:

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
| Basic earnings per common share: |  |  |
| Net income (loss) - basic | $(9321) | $9979 |
| Weighted average shares outstanding - basic | 46519 | 42619 |
| Basic earnings (loss) per common share | $(0.20) | $0.23 |

---

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

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
| Diluted earnings per common share: |  |  |
| Net income (loss) - diluted | $(9321) | $9979 |
| Weighted average shares outstanding - basic | 46519 | 42619 |
| Add: Dilutive effects of Restricted Stock Units |  | 843 |
| Weighted average shares outstanding - diluted | 46519 | 43462 |
| Diluted net income (loss) per share | $(0.20) | $0.23 |

---

The computation of diluted net loss per share for the three months ended March 31, 2026 excludes 389,276 potentially dilutive securities related to unvested restricted stock units as their inclusion would have been anti-dilutive.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(14) **CONTINGENCIES** 

Our Coal Operations subsidiary was party to litigation in which the plaintiffs alleged violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $2.8 million, which was recorded in operating expenses on our consolidated statements of operations for the year ended December 31, 2024. During the third quarter of 2025, we transferred $2.7 million into an escrow account and in late 2025 the settlement terms were approved by the court. At December 31, 2025, there were no further amounts accrued on our consolidated balance sheet related to this litigation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**(15)**  **AT MARKET AGREEMENT ("ATM") AND CONFIDENTIALLY MARKETED PUBLIC OFFERING ("CMPO")** 

*ATM*

On December 18, 2023, we entered into an At 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 days' notice, to terminate the Sales Agreement in our and the Agent's sole discretion. On December 16, 2025, the Company increased the aggregate gross sales proceeds under the ATM Program from $50.0 million to $100.0 million by amending the Sales Agreement.

During the three months ended March 31, 2026, we issued 10,832 shares of Common Stock under the ATM Program for net proceeds of $0.2 million. During the year ended December 31, 2025, we issued 697,227 shares of Common Stock under the ATM Program for net proceeds of $13.5 million. In January 2026, the Company delivered written notice to the Agent to terminate the Sales Agreement effective January 18, 2026. As a result of the termination of the Sales Agreement, the Company will not offer or sell any further shares under the ATM Program.

*CMPO*

In January 2026, the Company conducted a confidentially marketed public offering (the "CMPO") pursuant to a base prospectus and a final prospectus supplement that were filed with the SEC. The Company sold a total of 3,194,444 shares of common stock, at a price to the public of $18.00 per share for aggregate gross proceeds of approximately $57.5 million, including the exercise of the underwriter's option prior to deducting underwriting discounts, commissions, and other offering expenses of $3.7 million.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(16) **SUBSEQUENT EVENTS** 

On May 1, 2026, the Company entered into a Master Power Purchase and Sale Agreement Long-Form Confirmation Letter (the "Capacity PPA") with a subsidiary of a utility. The Capacity PPA provides for the sale of approximately two-thirds of the Company's accredited capacity from its Merom Generating Station, commencing in late 2028 and extending through mid-2040, and is expected to generate cumulative revenue in excess of $1.0 billion. The Capacity PPA is subject to customary regulatory approvals, including approval by the Indiana Utility Regulatory Commission ("IURC"). Completion of the IURC's review is anticipated in the second half of 2026.

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#### ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis, which should be read in conjunction with our consolidated financial statements and the discussion and analysis included in our 2025 10-K, is intended to assist in providing an understanding of changes in our results of operations and financial condition and is organized as follows:

&nbsp;&nbsp;&nbsp;&nbsp;•Forward-Looking Statements. This section provides a description of certain factors that could cause actual results or events to differ materially from anticipated results or events.

&nbsp;&nbsp;&nbsp;&nbsp;•Overview. This section provides a general description of our business and recent events.

&nbsp;&nbsp;&nbsp;&nbsp;•Material Changes in Results of Operations. This section provides an analysis of our results of operations for the three months ended March 31, 2026 and 2025.

&nbsp;&nbsp;&nbsp;&nbsp;•Material Changes in Financial Condition. This section provides an analysis of our liquidity and our condensed consolidated statements of cash flows.

The capitalized terms used below have been defined in the notes to our condensed consolidated financial statements. In the following text, the terms "we," "our," "the Company" and "us" may refer, as the context requires, to Hallador Energy Company ("Hallador") or collectively to Hallador and its subsidiaries.

Unless otherwise indicated, operational data is presented as of March 31, 2026.

**FORWARD-LOOKING STATEMENTS**

Certain statements and information in this Quarterly Report on Form 10-Q may constitute "forward-looking statements." These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words "anticipate," "believe," "continue," "estimate," "expect," "forecast," "may," "project," "will," and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• fluctuations in weather, natural gas and electricity commodity costs, inflation and economic conditions that impact demand of our customers and our operating results;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the outcome or escalation of current international hostilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in competition, or changes in electricity, natural gas or coal prices, demand, and availability which could affect our operating results and cash flows;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks associated with the expansion of our operations and properties;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks relating to Midcontinent Independent System Operator's ("MISO") Expedited Resource Addition Study ("ERAS") program review and approval process;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks relating to our ability to secure agreements in support of the development and construction of planned projects, including the expansion of the Merom Generating Station through the ERAS program;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• legislation, regulations, administrative actions (e.g., executive orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases ("GHG"), mining, miner health and safety, and health care, as well as those relating to data privacy protection;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in the geopolitical environment in industries in which our customers operate;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in attitude toward environmental, social, and governance ("ESG") matters among regulators, investors and parties with which we do business;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the effect of changes in taxes or tariffs and other trade measures, including uncertainty regarding tariffs on imports into the United States, which could impact the Company's procurement and sourcing strategies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks relating to inflation and increasing interest rates;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• liquidity constraints, including due to restrictions contained in our debt agreements or other arrangements and those resulting from any future unavailability of financing;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, including failures to make payments when due;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• customer delays or failure to take coal or electricity under contracts;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• adjustments made in price, volume or terms to existing coal or electricity contracts;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our productivity levels and margins earned on our coal or electricity sales;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in the availability of skilled labor;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our ability to maintain satisfactory relations with our employees;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers' compensation claims;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• increases in transportation costs and risk of transportation delays or interruptions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• operational interruptions due to geologic, permitting, labor, weather-related or other factors, including challenges in operating an aging coal-fired power plant;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• results of litigation, including claims not yet asserted;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• difficulty maintaining our surety bonds for mine reclamation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• decline in or change in the coal industry's share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks resulting from natural disasters;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• difficulty in making accurate assumptions and projections regarding landfill and mine reclamation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• uncertainties in estimating and replacing our coal reserves;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the impact of current and potential changes to federal or state tax rules and regulations, including the effects of the One Big Beautiful Bill Act ("OBBBA") or a loss or reduction of benefits from certain tax deductions and credits;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• difficulty obtaining commercial property insurance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• other factors, including those discussed in "Item 1A. Risk Factors" in our 2025 Form 10-K.

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If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in "Item 1A. Risk Factors" in our 2025 Form 10-K. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law.

You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; other reports filed by us with the U.S. Securities and Exchange Commission ("SEC"); our press releases; our website www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

**OVERVIEW**

***General***

Hallador is a vertically integrated, independent power producer ("IPP") and fuel company with operations primarily in Indiana. The Company operates across multiple stages of the energy supply chain, from accredited capacity and energy to coal. The Company's electric operations are located within the MISO footprint. Our operations include Hallador Power which provides accredited capacity and energy to utilities and other energy market participants through its MISO interconnection, and Sunrise which mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States.

***Operations***

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Company also holds 50% interests in Sunrise Energy, LLC ("Sunrise Energy") and Oaktown Gas, LLC ("Oaktown Gas"), which are accounted for using the equity method. Through its operating subsidiaries, the Company delivers three main products to its customers.

*Accredited Capacity.* Hallador Power, the Company's wholly-owned electric subsidiary, owns and operates the Merom Power Plant ("Merom"), a 1,080 MW coal-fired power generating station, consisting of two steam turbine generators. Unit 1 entered commercial operations in 1982 and Unit 2 in 1983. The units are dispatched through its MISO interconnection. In order to purchase energy through the MISO system, an end user must supply or purchase accredited capacity for an equivalent load. As accredited capacity is primarily available in large quantities from dispatchable sources of energy, such as natural gas and coal-fired power plants, Hallador Power sells accredited capacity to utilities and other energy market participants within the MISO system through Power Purchase Agreements ("PPA") and other bilateral transactions.

*Energy.* In addition to accredited capacity, Hallador Power sells wholesale energy to utilities, generation and transmission cooperatives, and other energy market participants within the MISO system through PPAs and other bilateral transactions, and sells on a spot basis in the day-ahead and real-time MISO markets.

*Coal.* Sunrise, the Company's wholly-owned mining subsidiary, mines coal from reserves found in the Illinois Basin ("ILB"). Coal mined by Sunrise is used as a primary fuel source for generating electricity at various power plants in the Midwest and Southeast United States. In addition, Sunrise has a developed infrastructure for the transport of coal, which is typically sold free on board from the shipping point, including rail networks and truck loading systems, facilitating the efficient movement of the resource from the mine to its customers. Sunrise's Oaktown Mining Complex is about twenty miles from Merom, which is located in Sullivan County, Indiana, enabling Merom and Sunrise to take advantage of low-cost fuel on a delivered basis.

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***Strategy and Management Focus***

We view our business as two integrated operations, "Electric Operations" (our gigawatt Merom power generating station), and "Coal Operations" (our coal mining and coal sales group).

We strive to achieve margin expansion through organic revenue growth and profitability in our operations by negotiating and fulfilling contracts for accredited capacity, wholesale energy, and thermal coal to utilities and other energy market participants. We continue to monitor opportunities to expand the volume of our electric generation capabilities through expansion of existing facilities utilizing MISO's ERAS program, or via acquisition. We continue to evaluate other strategic transactions that could add diversification, durability, scale, and geographic expansion opportunities to our Electric Operations. While these opportunities are limited and complex, we believe that Hallador is well-positioned to transform retiring and/or underperforming assets into future opportunities. This will enable us to supply high-demand end users, such as data centers and industrial customers, with minimal impact to retail consumers. In addition, we focus our organic capital investments on strategic maintenance projects to maintain our safe operational performance and improve the reliability of Merom.

As discussed further under *"Material Changes in Financial Condition — Capitalization"* below, we also seek to maintain our debt at levels that provide for attractive equity returns without assuming undue risk.

***Competition and Other External Factors***

We are experiencing competition in both our Electric and Coal Operations. This competition drives lower market prices for our products and services. Competitors for our Electric Operations include other power generators who bid into the MISO system, while competitors for our Coal Operations include other mining entities that are able to service our existing and potential customers via truck or rail within the Midwest and Southeast United States. 

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**MATERIAL CHANGES IN RESULTS OF OPERATIONS**

Our contracted forward sales for accredited capacity, energy, and coal are detailed below with estimated revenue from forward sales of $1.2 billion as of March 31, 2026.

**Forward Sales Position (unaudited)\***

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | **2026** | **2027** | **2028** | **2029** | **Total** |
| **Power** |  |  |  |  |  |
| **Accredited Capacity** |  |  |  |  |  |
| Average daily contracted accredited capacity MW | 781 | 782 | 668 | 340 |  |
| Average contracted accredited capacity price per MWd | $246 | $264 | $300 | $398 |  |
| Contracted accredited capacity revenue (in millions) | $52.82 | $75.26 | $73.28 | $20.44 | $221.80 |
| **Energy** |  |  |  |  |  |
| Contracted MWh (in millions) | 3.10 | 3.06 | 1.09 | 0.27 | 7.52 |
| Average contracted price per MWh | $43.74 | $46.50 | $52.94 | $51.33 |  |
| Contracted revenue (in millions) | $135.59 | $142.29 | $57.70 | $13.86 | $349.44 |
| Total Accredited Capacity & Energy Revenue (in millions) | $188.41 | $217.55 | $130.98 | $34.30 | $571.24 |
| **Coal** |  |  |  |  |  |
| Priced tons - 3rd party (in millions) | 2.10 | 2.50 | 0.50 |  | 5.10 |
| Avg price per ton - 3rd party | $55.73 | $56.74 | $59.00 |  |  |
| Contracted coal revenue - 3rd party (in millions) | $117.03 | $141.85 | $29.50 | $— | $288.38 |
| TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED | $305.44 | $359.40 | $160.48 | $34.30 | $859.62 |
| Priced tons - Intercompany (in millions) | 2.08 | 2.30 | 3.17 |  | 7.55 |
| Avg price per ton - Intercompany | $51.00 | $51.00 | $51.00 |  |  |
| Contracted coal revenue - Intercompany (in millions) | $106.08 | $117.30 | $161.67 | $— | $385.05 |
| TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT | $411.52 | $476.70 | $322.15 | $34.30 | $1244.67 |

---

\* Actual revenue related to forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions, including rollover of unfulfilled coal commitments into future periods, and potential force majeure events. Forward sales figures in the 2026 column are for the period from April 1, 2026 through December 31, 2026.

***Discussion and Analysis of our Reportable Segments***

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker ("CODM"), who is the Company's Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.

In addition to these reportable segments, the Company has a "Corporate and Other and Eliminations" category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including our 50% interests in Sunrise Energy and Oaktown Gas, which we account for using the equity method.

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#### Electric Operations

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
|  | **(in thousands)** | **(in thousands)** |
| Delivered Energy | $49562 | $72136 |
| Accredited Capacity Revenue | 15534 | 13807 |
| Electric Sales | $65096 | $85943 |
| Fuel | $(27527) | $(38071) |
| Other Operating Costs (1) | (29) | (8) |
| Other Operating and Maintenance Costs (2) | (8854) | (4527) |
| Cost of Purchased Power | (14863) | (6840) |
| Utilities | (134) | (676) |
| Labor | (8129) | (8143) |
| General and Administrative | (1310) | (1535) |
| Segment EBITDA | 4250 | 26143 |
| Other Operating Revenue | 137 | 87 |
| Depreciation, Depletion and Amortization | (6383) | (5161) |
| Asset Retirement Obligations Accretion | (131) | (120) |
| Interest Income | 36 |  |
| Interest Expense | (2947) | (1732) |
| Income before Income Taxes | $(5038) | $19217 |

---

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable included in fuel and other operating costs.

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
|  | **(per MWh)** | **(per MWh)** |
| MWh Generated (in thousands) | 938 | 1422 |
| MWh Purchased (in thousands) | 183 | 132 |
| MWh Sold (in thousands) | 1121 | 1554 |
| Delivered Energy | $44.21 | $46.42 |
| Accredited Capacity Revenue | 13.86 | 8.88 |
| Electric Sales | $58.07 | $55.30 |
| Fuel | $(24.56) | $(24.50) |
| Other Operating Costs (1) | (0.03) | (0.01) |
| Other Operating and Maintenance Costs (2) | (7.90) | (2.91) |
| Cost of Purchased Power | (13.26) | (4.40) |
| Utilities | (0.12) | (0.44) |
| Labor | (7.25) | (5.24) |
| General and Administrative | (1.17) | (0.99) |
| Segment EBITDA  | 3.78 | 16.81 |
| Other Operating Revenue | 0.12 | 0.06 |
| Depreciation, Depletion and Amortization | (5.69) | (3.32) |
| Asset Retirement Obligations Accretion | (0.12) | (0.08) |
| Interest Income | 0.03 |  |
| Interest Expense | (2.63) | (1.11) |
| Income before Income Taxes | $(4.51) | $12.36 |

---

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable included in fuel and other operating costs.

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Segment operating revenues from electric operations decreased $20.8 million, or 24.3%, compared to the first quarter of 2025, attributable to a $22.6 million decrease in sales of delivered energy partially offset by a $1.7 million increase in accredited capacity revenue. Our Electric Operations generated 0.5 million fewer MWh, but purchased an additional 0.1 million MWh for resale resulting in a net decrease of energy sales of 0.4 million MWh, a decrease of 27.9% compared to the first quarter of 2025. Lower plant availability in the first quarter of 2026 due to equipment issues at Merom had a significant impact on the total MWh generated. The impacted generating unit is scheduled to undergo a major maintenance outage beginning in May 2026, which we expect will improve performance upon completion. The price per MWh for delivered energy decreased 4.8% year-over-year from $46.42 for the three-month period ended March 31, 2025 to $44.21 in 2026. Accredited capacity revenue increased 12.5% to $15.5 million for the three-month period ended March 31, 2026 from $13.8 million in the comparable prior year period.

Fuel costs on a segment basis decreased $10.5 million, or 27.7%, from the first quarter of 2025. Fuel costs on a consolidated basis decreased $0.2 million or 1.5%, from the first quarter of 2025. The decrease is due to electricity generation falling by 0.5 million MWh, or 34.0%. We used 0.2 million tons less in production on both a segment and consolidated basis, as we utilized 0.2 million less tons produced at the Oaktown mining complex in 2026 compared to 2025. The decrease in electric power generation was attributable to the aforementioned equipment issues, which resulted in 0.5 million lower MWh generated, compared to the same period in 2025. The weather contributed to higher demand for electricity and natural gas causing an increase in the average spot price at Chicago citygate of $1.30 per thousand cubic feet to $5.70 per thousand cubic feet in January 2026 compared to January 2025. Total fuel costs were impacted by an increase in the cost of coal consumed from $53.80 per ton in 2025 to $54.58 per ton in 2026.

Other operating and maintenance costs increased $4.3 million, or 95.6%, from the first quarter of 2025. The increase was driven by increased maintenance activities attributable to the aforementioned equipment issues at Merom. In addition to the increased maintenance activities in the first quarter of 2026, the impacted generating unit will receive a major maintenance outage beginning in May.

Cost of purchased power increased $8.0 million, or 117.3%, from the first quarter of 2025. When there is an outage at one of the generating units at Merom or energy hours at the Merom Hub are priced below our production cost, we have the option to make economic net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power. In 2026, we purchased an incremental 51,000 MWh compared to 2025, an increase of 38.6% that was further impacted by the energy pricing dynamics at the time of the purchases.

Utilities expense decreased $0.5 million, or 80.2%, in the first quarter of 2026 compared to 2025. The change was attributable to decreased production at Merom, as well as new meters installed in 2025 that allow for active management of pricing of auxiliary power in the day-ahead market.

Labor expenses were largely flat for the first quarter of 2026 versus the comparable period in 2025 as headcount was relatively stable year-over-year.

Interest expense increased $1.2 million, or 70.2%, from the first quarter of 2025. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in 2024 and 2025.

Income before income taxes decreased $24.3 million from $19.2 million of income before taxes in the first quarter of 2025 to a loss before taxes of $5.0 million in the first quarter of 2026, which is attributable to the items described in the discussion above.

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#### Coal Operations

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
|  | **(in thousands)** | **(in thousands)** |
| Coal Sales | $46412 | $54774 |
| Fuel | $(528) | $(556) |
| Other Operating and Maintenance Costs | (20273) | (23854) |
| Utilities | (3199) | (3476) |
| Labor | (19259) | (18886) |
| General and Administrative | (2211) | (2313) |
| Segment EBITDA | 942 | 5689 |
| Other Operating Revenue | 1140 | 1261 |
| Depreciation, Depletion and Amortization | (4204) | (9797) |
| ARO Accretion | (277) | (307) |
| Exploration Costs | (84) | (21) |
| Gain on Disposal or Abandonment of Assets, Net | 201 | 21 |
| Interest Income | 111 | 63 |
| Interest Expense | (808) | (1991) |
| Income (Loss) before Income Taxes | $(2979) | $(5082) |

---

---

| | | |
|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  |
|  | **2026** | **2025** |
|  | **(per ton)** | **(per ton)** |
| Tons Sold (in thousands) | 854 | 1071 |
| Coal Sales | $54.35 | $51.14 |
| Fuel | $(0.62) | $(0.52) |
| Other Operating and Maintenance Costs | (23.74) | (22.27) |
| Utilities | (3.75) | (3.25) |
| Labor | (22.55) | (17.63) |
| General and Administrative | (2.59) | (2.16) |
| Segment EBITDA  | 1.10 | 5.31 |
| Other Operating Revenue | 1.33 | 1.18 |
| Depreciation, Depletion and Amortization | (4.92) | (9.15) |
| ARO Accretion | (0.32) | (0.29) |
| Exploration Costs | (0.10) | (0.02) |
| Gain on Disposal or Abandonment of Assets, Net | 0.24 | 0.02 |
| Interest income | 0.13 | 0.06 |
| Interest expense | (0.95) | (1.86) |
| Income (Loss) before Income Taxes | $(3.49) | $(4.75) |

---

Segment operating revenue from coal operations (including intercompany sales to Merom) decreased $8.4 million, or 15.3%, compared to the first quarter of 2025. The decrease was driven by lower volume partially offset by an increase in the average sales price for our coal. We sold 0.9 million tons of coal during the first quarter of 2026, a decrease of 0.2 million tons, or 20.3%, versus 2025. Our average sales price, on a segment basis, increased $3.21 per ton from $51.14 per ton to $54.35 per ton. The decreased sales were driven by lower coal demand from Merom due to the aforementioned equipment issues. Sunrise sold 0.3 million fewer tons of coal to Merom, offset by a 7.2% increase in tons sold to third parties in the first quarter of 2026 compared to 2025. On a consolidated basis, third party sales increased $4.9 million, or 16.2%, versus the first quarter of 2025 attributable to 0.3 million incremental tons sold to third parties, supplemented by an 8.4% increase in our average third party price per ton.

Other operating and maintenance costs decreased $3.6 million, or 15.0%, which is attributable to the decrease in total tons sold of 0.2 million, or 20.3%, versus the first quarter of 2025, partially offset by mine expansion costs at Oaktown. Labor expenses increased $0.4 million, or 2.0%, from the first quarter of 2025; however, because tons sold declined 20.3%, labor cost per ton sold rose $4.92 as production at the mine outpaced coal sales.

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Depreciation, Depletion and Amortization decreased by $5.6 million, or 57.1%, compared to the first quarter of 2025, partially attributable to the lower production during the first quarter of 2026. Following the impairment of our coal operations, the cost basis of our coal operations assets upon which depreciation, depletion and amortization is calculated was also lower resulting in significantly lower expense.

Interest expense decreased $1.2 million, or 59.4%, from $2.0 million for the three months ended March 31, 2025 to $0.8 million in 2026. The decrease is attributable to the paydown of the Company's bank facility from $30.0 million at December 31, 2025 to zero at March 31, 2026.

Loss before income taxes narrowed by $2.1 million, or 41.4% compared to the first quarter of 2025. The main drivers of this change in loss before income taxes 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** | **2nd 2025** | **3rd 2025** | **4th 2025** | **1st 2026** | **T4Qs** |
| Tons produced | 1059 | 1034 | 905 | 907 | 3905 |
| Tons sold | 890 | 1355 | 995 | 854 | 4094 |
| Wash plant recovery in % | 66% | 64% | 57% | 59% |  |
| Capex (Coal Operations) | $5793 | $6873 | $6449 | $3792 | $22907 |
| Capex per ton sold (Coal Operations) | $6.51 | $5.07 | $6.48 | $4.44 | $5.60 |
| Average cost per ton sold⁽ⁱ⁾ | $46.03 | $42.74 | $46.75 | $50.66 |  |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **All Mines** | **2nd 2024** | **3rd 2024** | **4th 2024** | **1st 2025** | **T4Qs** |
| Tons produced | 889 | 873 | 971 | 1020 | 3753 |
| Tons sold | 849 | 926 | 875 | 1071 | 3721 |
| Wash plant recovery in % | 59% | 60% | 62% | 64% |  |
| Capex (Coal Operations) | $7560 | $6810 | $11079 | $6244 | $31693 |
| Capex per ton sold (Coal Operations) | $8.90 | $7.35 | $12.66 | $5.83 | $8.52 |
| Average cost per ton sold⁽ⁱ⁾ | $49.94 | $52.22 | $43.25 | $43.65 |  |

---

(i) Average cost per ton sold is calculated as the sum of the Coal Operation's fuel, other operating and maintenance costs, utilities and labor costs divided by tons sold for the respective period in this table. Coal Operations costs are presented in the "Discussion and Analysis of our Reportable Segments" above.

**EARNINGS (LOSS) PER SHARE**

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **2nd 2025** | **3rd 2025** | **4th 2025** | **1st 2026** |
| Basic | $0.19 | $0.56 | $(0.01) | $(0.20) |
| Diluted | $0.19 | $0.55 | $(0.01) | $(0.20) |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **2nd 2024** | **3rd 2024** | **4th 2024** | **1st 2025** |
| Basic | $(0.27) | $0.04 | $(5.06) | $0.23 |
| Diluted | $(0.27) | $0.04 | $(5.06) | $0.23 |

---

#### INCOME TAXES
Our effective tax rate ("ETR") is estimated at ~5.2% and ~0% for the three months ended March 31, 2026 and 2025, respectively. For the three months ended March 31, 2026, we estimated our annual ETR 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.

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#### RESTRICTED STOCK GRANTS
See *"Item 1. Financial Statements - Note 8 - Stock Compensation Plans"* for a discussion of restricted stock unit ("RSUs").

#### MATERIAL CHANGES IN FINANCIAL CONDITION
*Sources and Uses of Cash*

We are a holding company that is dependent on the capital resources of our subsidiaries to satisfy our liquidity requirements at the corporate level. Each of our significant operating subsidiaries typically generate cash from operating activities, but our ability to access the liquidity of these and other subsidiaries may be limited by tax and legal considerations, and other factors.

*Cash and cash equivalents*

Hallador had $43.4 million of cash and restricted cash as of March 31, 2026 versus $15.4 million at December 31, 2025.

*Liquidity of Hallador*

Our short-term sources of corporate liquidity include (i) cash and cash equivalents held by Hallador, (ii) cash provided by operations, (iii) interest income received on our cash and cash equivalents and, (iv) borrowing availability under our new credit facility. For the details of the borrowing availability under our credit facility, see *"Item 1. Financial Statements - Note 4 – Bank Debt"* to our unaudited condensed consolidated financial statements.

The liquidity of Hallador generally is used to fund (i) capital expenditures, (ii) debt service requirements and (iii) general and administrative expenses, as well as to settle certain obligations that are not included on our March 31, 2026 unaudited condensed consolidated balance sheet. In this regard, we have commitments related to (a) leases of railcars that qualify for the short-term lease exception and (b) certain operating costs associated with our Electric Operations and our Coal Operations.

From time to time, we may also require liquidity in connection with (i) acquisitions and other investment opportunities, (ii) the satisfaction of contingent liabilities, (iii) capital distributions to Hallador equity owners, (iv) the repayment of third party debt, or (v) income tax payments. No assurance can be given that any external funding would be available to us on favorable terms, or at all.

Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents. As of March 31, 2026, we had additional borrowing capacity of $60.8 million under the New Revolving Credit Facility and total liquidity of $97.5 million. Our additional borrowing capacity is net of $14.2 million in outstanding letters of credit as of March 31, 2026 that were required to maintain surety bonds and other credit support obligations.

*Consolidated Statement of Cash Flows Summary.*

The first quarter of 2026 and 2025 unaudited condensed consolidated statements of cash flows are summarized as follows:

---

| | | | |
|:---|:---|:---|:---|
|  | **Three Months Ended March 31,**  | **Three Months Ended March 31,**  | |
|  | **2026** | **2025** | <br>**Change** |
| Net cash provided by operating activities | $20496 | $38419 | $(17923) |
| Net cash used in investing activities | (7480) | (11672) | 4192 |
| Net cash (used in) provided by financing activities | 14975 | (22693) | 37668 |
| Increase in cash, cash equivalents, and restricted cash | $27991 | $4054 | $23937 |

---

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*Operating Activities.* The decrease in net cash provided by our operating activities is primarily attributable to the combination of (i) lower Adjusted EBITDA and related working capital items, (ii) increased inventory levels, (iii) incremental amortization of prepaid forward sales contracts for cash received in prior periods, and (iv) lower cash payments of interest, partially offset by incremental cash received for annual sales of accredited capacity compared to the first quarter of 2025. Consolidated Adjusted EBITDA is a non-GAAP measure, which investors should view as a supplement to, and not a substitute for, GAAP measures of performance included in our condensed consolidated statements of operations.

*Investing Activities.* The change in net cash used by our investing activities is primarily attributable to (i) a decrease in our capital expenditures of $4.0 million partially attributable to lower capitalization of mine development costs and (ii) a $0.2 million increase in the proceeds from sales of equipment.

For the three months ended March 31, 2026, capital expenditures ("Capex") was $7.7 million allocated as follows (in millions):

---

| | |
|:---|:---|
| Oaktown  | $3.8 |
| Merom | 2.3 |
| Merom - ELG | 1.3 |
| ERAS Project | 0.3 |
| &nbsp;&nbsp;Capex per the condensed consolidated statements of cash flows | $7.7 |

---

We expect our 2026 Capex to remain broadly stable as compared to our 2025 Capex, excluding any impacts of the ERAS Project. The actual amount of our 2026 Capex may vary from our expectations for a variety of reasons, including (i) changes in (a) the competitive or regulatory environment, (b) business plans, or (c) our expected future operating results and (ii) the availability of sufficient capital. Accordingly, no assurance can be given that our actual Capex will not vary materially from our expectations.

*Financing Activities.* The increase in net cash provided by our financing activities is primarily attributable to the net effect of (i) an increase in cash of $53.8 million from the net proceeds of the CMPO, (ii) a reduction in cash attributable to higher net repayments of bank debt of $9.0 million, and (iii) a decrease in cash from incremental lease financing payments of $1.5 million.

*Capitalization*

We seek to maintain our debt at levels that provide for equity returns without assuming undue risk. Our ability to service or refinance our debt and to maintain compliance with the leverage covenants in our credit agreement is dependent primarily on our ability to maintain or increase the Adjusted EBITDA of our consolidated businesses, maintain adequate liquidity and coverage of fixed charges, and to achieve adequate returns on our capital expenditures and acquisitions. Consolidated Adjusted EBITDA is a non-GAAP measure, which investors should view as a supplement to, and not a substitute for, GAAP measures of performance included in our condensed consolidated statements of operations. In addition, our ability to obtain additional debt financing is limited by the incurrence-based leverage covenants contained in our debt instruments. For example, if the Adjusted EBITDA of our business was to decline, our ability to obtain additional debt could be limited.

Prior to March 5, 2026, the Company was party to a credit agreement with PNC Bank, National Association (in its capacity as administrative agent, "PNC Bank"). As of December 31, 2025, our bank debt under the PNC Bank credit facility was $30.0 million, which was repaid subsequent to year-end as further described below.

On March 5, 2026, Hallador entered into a credit agreement with Texas Capital Bank and Old National Bank, among others, that replaces the Credit Agreement with PNC Bank and includes a $75.0 million revolving credit facility (the "New Revolving Credit Facility") and a $45.0 million delayed draw term loan (the "Delayed Draw Term Loan", and together with the New Revolving Credit Facility, the "New Credit Facility"). The New Credit Facility bears interest with margins ranging from 2.25% to 3.75% above SOFR or the applicable base rate, subject to a SOFR floor of 1.00%. The applicable margin is determined based upon the Company's leverage ratio and the type of loan drawn. The New Credit

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Facility includes a commitment fee of 0.50% on any daily unused portions of the New Revolving Credit Facility. If the Delayed Draw Term Loan occurs, which is subject to meeting certain conditions, the principal balance of the Delayed Draw Term Loan shall be due and payable in equal quarterly installments of 2.5% of the original principal amount of such Delayed Draw Term Loan with a final payment of the remaining balance upon maturity. The New Credit Facility matures on March 5, 2029, and is collateralized by substantially all our assets. When drawn, the proceeds from the New Credit Facility may be used for ongoing working capital and general corporate purposes.

See "*Item 1. Financial Statements - Note 4 – Bank Debt*" to our unaudited condensed consolidated financial statements for additional discussion about our bank debt and related liquidity.

*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 $18.0 million, including $6.3 million at Merom, presented as asset retirement obligations ("ARO") 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 $30.9 million to cover ARO.

**CRITICAL ACCOUNTING ESTIMATES**

For a description of our critical accounting policies and estimates, refer to "*Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations*" included in our 2025 Form 10-K. For a discussion of recent accounting pronouncements, newly adopted and recent accounting pronouncements not yet adopted, see "*Note 2 – Recent Accounting Pronouncements"* to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report. We did not have any material changes in critical accounting policies, estimates, judgments and assumptions during the three months ended March 31, 2026.

#### ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's power generation and mining activities, or with existing or forecasted financial or commodity transactions. The types of market risks that Hallador is exposed to are commodity price risk, interest rate risk, inflation risk, and counterparty credit risk.

***Commodity Price Risk***

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. We manage the commodity price risk of the Company's generation and mining operations by entering into various instruments to manage the variability in future cash flows from forecasted sales and purchases of power and fuel. These instruments include prepaid forward contracts, PPAs, and other bilateral agreements. Hallador uses these agreements to manage and fix the prices of certain purchases and sales to alleviate market risk and improve visibility into future results. See the *"Forward Sales Position"* table within the *"Material Changes in Results of Operations"* section of *"Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations"*.

We are exposed to market price fluctuations for emission credits related to our investments in Sunrise Energy and Oaktown Gas, which had an aggregate value of $2.5 million at March 31, 2026. For additional information regarding our investments in Sunrise Energy and Oaktown Gas, see *"Item 1. Financial Statements - Note 11. – Equity Method Investments"* to our condensed consolidated financial statements.

[**Table of Contents**](#TOC)

***Interest Rate Risk***

We are exposed to changes in interest rates primarily as a result of our borrowing activities, which include instruments with variable rates. Our primary exposure to variable rates is through our SOFR-indexed credit facilities.

In general, we monitor the interest rate market and determine whether to enter into instruments to protect against increases in the interest rates on our variable-rate debt. From time to time, we may use interest rate swaps, interest rate cap, floor or collar agreements that lock in a maximum interest rate if variable rates rise, but also may allow our company to benefit, to a limited extent in the case of collars, from declines in market rates. We use judgment to determine the appropriate composition of interest rate derivative instruments, taking into account the relative costs and benefits in light of current and expected future market conditions, liquidity issues and other factors. As of March 31, 2026 and December 31, 2025, we did not hold any interest rate derivative instruments.

*Weighted Average Variable Interest Rate.* At March 31, 2026 and December 31, 2025, the outstanding principal amount of our variable-rate indebtedness aggregated zero and $30.0 million, respectively, and the weighted average interest rate (including margin) on such variable-rate indebtedness was approximately 7.16% and 8.17%, respectively, excluding the effects of interest rate derivative contracts, deferred financing costs, original issue premiums or discounts and commitment fees, all of which affect our overall cost of borrowing.

***Inflation Risk***

We are subject to inflationary pressures with respect to labor, procurement of electrical and mining equipment, and other costs. While we attempt to increase our revenue to offset increases in costs, there is no assurance that we will be able to do so. Therefore, costs could rise faster than associated revenue, thereby resulting in a negative impact on our operating results, cash flows and liquidity. The economic environment in which we operate is a function of government, economic, fiscal and monetary policies and various other factors beyond our control that could lead to inflation. We are unable to predict the extent that price levels might be impacted in future periods in the markets in which we operate.

***Counterparty Credit Risk***

We are exposed to the risk that the counterparties to our undrawn debt facilities and cash investments will default on their obligations to us. We manage these credit risks through the evaluation and monitoring of the creditworthiness of, and concentration of risk with, the respective counterparties. In this regard, credit risk associated with our undrawn debt facilities is spread across multiple counterparties, however notwithstanding, the default of certain counterparties could have a significant impact on our business. Most of our cash currently is invested in either (i) money market funds, including funds that invest in high-quality short-term instruments that preserve principal and offer daily liquidity, or (ii) overnight deposits with banks that transfer balances nightly into repurchase agreements collateralized by high-quality securities, including US government instruments. To date, neither the access to nor the value of our cash and cash equivalent balances have been adversely impacted by liquidity problems of financial institutions.

We invest our cash with financial institutions that meet high credit quality standards. We are exposed to the credit risk of these financial institutions and to interest rate risk in relation to the interest earning potential of our cash and cash equivalent balances. In order to mitigate these risks, we actively manage the deposits of our cash balances in light of our and our subsidiaries' forecasted liquidity requirements.

At March 31, 2026 and December 31, 2025, our exposure to counterparty credit risk included (i) cash and cash equivalents and restricted cash of $43.4 million and $15.4 million, respectively, and (ii) aggregate availability of undrawn debt facilities of $60.8 million and $28.8 million, respectively.

While we currently have no specific concerns about the creditworthiness of any counterparty for which we have material credit risk exposures, we cannot rule out the possibility that one or more of our counterparties could fail or otherwise be unable to meet its obligations to us. Any such instance could have an adverse effect on our cash flows, results of operations, financial condition and/or liquidity.

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Although we actively monitor the creditworthiness of our key vendors, the financial failure of a key vendor could disrupt our operations and have an adverse impact on our revenue and cash flows.

#### 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 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 upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.

**CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING**

There have been no changes to our internal control over financial reporting during the quarter ended March 31, 2026, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

**PART II - OTHER INFORMATION**

#### ITEM 1. LEGAL PROCEEDINGS
See *Item 1. Financial Statements - Note 14. – "Contingencies"* to our condensed consolidated financial statements. Except as described therein, the Company is not currently a party to any legal proceedings that management believes, either individually or in the aggregate, would reasonably be expected to have a material adverse effect on the Company's business, results of operations, financial condition, or liquidity.

**ITEM 1A. RISK FACTORS**

There have been no material changes to the risk factors disclosed in Part I, Item 1A, "Risk Factors" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, filed with the SEC on March 12, 2026.

#### ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
During the three months ended March 31, 2026, all sales and issuances of the Company's equity securities were registered under the Securities Act of 1933, as amended. Accordingly, during the period covered by this report, the Company did not engage in any unregistered sales of its equity securities that would be required to be disclosed pursuant to Item 701 of Regulation S-K. For a description of the Company's registered equity issuances during the quarter, including shares issued under the ATM Program and the CMPO, see *Item 1. Financial Statements - Note 15 – "At Market Agreement ("ATM") and Confidentially Marketed Public Offering ("CMPO")"* to our condensed consolidated financial statements.

**ITEM 3. DEFAULTS UPON SENIOR SECURITIES**

None.

**ITEM 4. MINE SAFETY DISCLOSURES**

See [Exhibit 95.1](hnrg-20260331xex95d1.htm) to this Form 10-Q for a listing of our mine safety violations.

[**Table of Contents**](#TOC)

#### ITEM 5. OTHER INFORMATION
None.

*Rule 10b5-1 Trading Arrangements*

During the three months ended March 31, 2026, no director or officer of Hallador adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408 of Regulation S-K.

#### ITEM 6. EXHIBITS

---

| | |
|:---|:---|
| **Exhibit No.** | **Document** |
| 1.1 | [Underwriting Agreement dated January 13, 2026](https://www.sec.gov/Archives/edgar/data/788965/000110465926004150/tm263288d1_ex1-1.htm)<sup>(1)</sup> |
| 10.1 | **[Credit Agreement, dated March 5, 2026, among Hallador Energy Company, the lenders party thereto, the letter of credit issuers party thereto and Texas Capital Bank, as administrative agent incorporated by reference to Form 8-K filed on March 10, 2026 <sup>(2)</sup>](https://www.sec.gov/Archives/edgar/data/788965/000110465926025949/hnrg-20260305xex10d1.htm)** |
| 10.2 | **[Master Power Purchase And Sale Agreement Long-Form Confirmation Letter dated May 1, 2026**\***](hnrg-20260331xex10d2.htm)** |
| 31.1 | [SOX 302 Certification - Chief Executive Officer](hnrg-20260331xex31d1.htm)\* |
| 31.2 | [SOX 302 Certification - Chief Financial Officer](hnrg-20260331xex31d2.htm)\* |
| 31.3 | [SOX 302 Certification – Chief Accounting Officer](hnrg-20260331xex31d3.htm)\* |
| 32 | [SOX 906 Certification](hnrg-20260331xex32.htm)\* |
| 95.1 | [Mine Safety Disclosures](hnrg-20260331xex95d1.htm)\* |
| 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)\* |

---

\*Filed herewith.

<sup>(1)</sup> Incorporated by reference to Form 8-K filed on January 15, 2026.

<sup>(2)</sup> Incorporated by reference to Form 8-K filed on March 10, 2026.

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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: May 6, 2026 | /s/BRENT K. BILSLAND |
|  | Brent K. Bilsland, Chairman, President and CEO  |
| Date: May 6, 2026 | /s/TODD E. TELESZ |
|  | Todd E. Telesz, CFO  |
| Date: May 6, 2026 | /s/ERIC VAN DEMAN |
|  | Eric Van Deman, CAO  |

---

## Exhibit 10.2

***Execution Copy***

**EXHIBIT 10.2**

**Master Power Purchase and Sale Agreement**

**LONG-FORM CONFIRMATION LETTER** 

This confirmation letter (this "<u>Confirmation</u>"), dated as of May 1, 2026 (the "<u>Execution Date</u>") shall confirm the Transaction between NIPSCO Generation, LLC ("<u>Buyer</u>"), and Hallador Power Company, LLC ("<u>Seller</u>") regarding the sale/purchase of the Product under the following terms and conditions as follows. Capitalized terms used but not defined herein or in the Master Agreement shall have the meanings ascribed to such terms in the applicable MISO Rules.

Seller:Hallador Power Company, LLC

Buyer:NIPSCO Generation, LLC

---

| | |
|:---|:---|
| Product: | "<u>Zonal Resource Credits</u>" (or "<u>ZRCs</u>") for Generation Resources located within Locational Resource Zone 6 (as each such term is defined in (i) the Midcontinent Independent System Operator, Inc. ("<u>MISO</u>") Open Access Transmission, Energy and Operating Reserve Markets Tariff as may be amended from time to time ("<u>MISO Tariff</u>"); and/or (ii) the MISO Resource Adequacy Business Practices Manual as may be amended from time to time ("<u>RA BPM</u>", together with the MISO Tariff referred to as the "<u>MISO Rules</u>"); *provided*, *however*, that if there is a conflict between (a) the MISO Tariff and the RA BPM, the MISO Tariff shall prevail, or (b) the MISO Tariff and any terms of the Master Agreement which may also be applicable to the definition of and obligations arising under the MISO Tariff from "ZRC," the MISO Tariff shall also prevail).  |

---

One ZRC represents one megawatt ("<u>MW</u>") of Seasonal Accredited Capacity that qualifies to satisfy the resource adequacy requirements of Module E-1, or any successor system, of the MISO Tariff for the relevant Season.

---

| | |
|:---|:---|
| Product Source: | Subject to the additional terms of this Confirmation, the Product is to be sourced from Merom Units 1 and 2 (each a "<u>Unit</u>" and collectively, the "<u>Units</u>") at Seller's generation station located in Sullivan County, Indiana (the "<u>Merom Generation Station</u>"), which is physically located within the current geographic and electrical boundaries of MISO's Locational Resource Zone 6 ("<u>Zone 6</u>");  |

---

Term: The "Term" of this Confirmation shall commence on the Execution Date and expire on the last day of the Delivery Term.

------

Delivery Term: Commencing on September 1, 2028, and continuing through and including May 31, 2040.

---

| | |
|:---|:---|
| Contract Year: | Each period of (a) September 1, 2028, through and including May 31, 2029 (the "<u>Initial Contract Year</u>") and (b) following the Initial Contract Year, each June 1 through May 31 (of the following calendar year) during the Delivery Term (each corresponding to a Planning Year of MISO). |

---

Contract Quantity /

Contract Price /

Annual Capacity

Payment: The Contract Quantity, Contract Price and Annual Capacity Payment applicable to the Product being sold/purchased hereunder shall be as set out in the table attached hereto as <u>Exhibit A</u>.

If Buyer chooses to use the Product sold hereunder to satisfy its resource adequacy obligations in a Local Resource Zone other than Zone 6, then Buyer shall be solely responsible for any inter-zonal delivery charges, auction price differences, or similar charges that may be assessed pursuant to the MISO Rules in order for the Zonal Resource Credits to be used to meet the resource adequacy requirements of Buyer's load in such other Local Resource Zone. Each of the Parties hereby warrants to the other Party that it will comply with all requirements of the MISO Rules related to the Product, including, as to Buyer, the MISO Rules regarding capacity offer requirements and as to Seller, the MISO Rules regarding energy offer requirements.

Special Conditions:

1. <u>State Regulatory Approval</u>.

The commencement of the Delivery Term and the obligations of the Parties hereunder are both expressly subject to Buyer having satisfied the following conditions (collectively, the "<u>State Regulatory Approval Conditions</u>"):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) within not more than forty-five (45) days following the Execution Date (the " <u>Filing Date</u> "), Buyer, together with Northern Indiana Public Service Company LLC (" <u>NIPSCO</u> ") shall have jointly filed with the Indiana Utility Regulatory Commission (the " <u>State Regulatory Agency</u> ") a request for the State Regulatory Agency to approve, without limitation or modification and by way of a final, non-appealable written order, (i) sales by Buyer to NIPSCO of the Contract Quantity of Product to be acquired by Buyer under this Confirmation, and (ii) for Buyer to make such sales to NIPSCO pursuant to the terms and conditions of that certain Power Purchase Agreement to be entered into between Buyer and NIPSCO (the " <u>Buyer-NIPSCO Agreement</u> ") (the foregoing approval by the State Regulatory Authority being the " <u>State Regulatory Approval</u> "); and

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) by the earlier of (the " <u>State Regulatory Approval Deadline</u> "): (i) one hundred fifty (150) days following the Filing Date, or (ii) one hundred ninety five (195) days following the Execution Date, to have obtained the State Regulatory Approval, without the imposition of any conditions applicable to the Buyer-NIPSCO Agreement unsatisfactory to Buyer in Buyer's sole discretion, or the imposition of any conditions on Buyer which are required to apply to this Confirmation or any modifications hereto and which, in the sole discretion of Seller, are unsatisfactory to Seller; *provided, however*, as to Buyer, the retention of the ongoing jurisdiction of the State Regulatory Agency over the performance of Buyer and NIPSCO under the Buyer-NIPSCO Agreement shall not be an unsatisfactory imposition or condition of the State Regulatory Approval.

Buyer shall use commercially reasonable efforts to satisfy the State Regulatory Approval Conditions on or before the State Regulatory Approval Deadline, and Seller shall reasonably cooperate with Buyer's efforts to satisfy the State Regulatory Approval Conditions; *provided* that Seller shall not be required to make any statements as to or represent for any purposes that the sale of the Product under this Confirmation to Buyer qualifies or is otherwise authorized for sale by Buyer to NIPSCO under the Buyer-NIPSCO Agreement or that such Buyer-NIPSCO Agreement in any way complies with the regulations and requirements of the State Regulatory Authority.

Other than the Parties obligations with respect to the satisfaction of the State Regulatory Approval Conditions as set out in this <u>Section 1</u> and obligations of confidentiality as set out in Section 10.11 of the Master Agreement (as modified by <u>Section 9(a)</u>), which each become effective as of the Execution Date, the Parties' obligations under this Confirmation shall commence and this Confirmation shall become effective on the date that all State Regulatory Approval Conditions are satisfied or waived by Buyer (such date, the "<u>Effective Date</u>"). If any of the State Regulatory Approval Conditions have not been satisfied or waived on or before the occurrence of the State Regulatory Approval Deadline, either Party may terminate this Confirmation upon written notice to the other Party, in which case neither Party shall have any obligations to the other Party hereunder, save to the extent of any ongoing obligations of confidentiality as set out in Section 10.11 of the Master Agreement (as modified by <u>Section 9(a)</u>).

2. <u>Delivery and Receipt</u>.

Seller shall accomplish delivery of the Contract Quantity of the Product for each Contract Year by submitting the transaction(s) in MISO's MECT system (or any successor system) to electronically assign the Contract Quantity to Buyer. Seller shall give prompt notice to Buyer of such submittal. Buyer shall accomplish receipt of the Contract Quantity for each Contract Year by confirming the transaction(s) submitted by Seller in the MECT. Buyer shall give Seller prompt notice of Buyer's receipt. With respect to each Contract Year, Seller and Buyer shall accomplish delivery and receipt of the applicable Contract Quantity by submitting and confirming the transaction(s) in the MECT, by the earlier of: (i) ten (10)

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Business Days after MISO allocates ZRCs in the MECT for such Contract Year; and (ii) ten (10) Business Days prior to the first day of the MISO Planning Resource Auction ("<u>PRA</u>") for the relevant Contract Year (each of the foregoing being a "<u>Transfer Deadline</u>"); *provided*, *however*, for purposes of the delivery of the Contract Quantity for the Initial Contract Year, Seller shall submit the transaction(s) in the MECT system within not more than five (5) Business Days of the commencement of the Delivery Term. The submitting and confirming of the appropriate transaction(s) in the MECT shall be conducted by the Parties in accordance with the requirements of the MISO Rules and other applicable rules adopted by the MISO regarding the MECT.

3. <u>Payment Terms.</u>

Buyer shall pay Seller the Annual Capacity Payment set forth in <u>Exhibit A</u> for the Initial Contract Year and each applicable Contract Year thereafter within ten (10) Business Days of the Seller having delivered an invoice to Buyer, which invoice will be provided to Buyer subsequent to Seller having submitted and confirmed each of the appropriate transaction(s) in the MECT to assign the applicable Contract Quantity for the Initial Contract Year and each such subsequent Contract Year to Buyer. The Parties acknowledge and agree that the payment terms described herein shall supersede and replace <u>Section 6.1</u> (Billing Period) and the first sentence of <u>Section 6.2</u> (Timeliness of Payment) of the Master Agreement. Buyer shall have no obligation to pay any portion of the Annual Capacity Payment set forth in <u>Exhibit A</u> that is attributable to any ZRCs not actually delivered by Seller to Buyer in the MECT, and in the event that Seller fails to deliver all or part of the Contract Quantity of the Product by the applicable Transfer Deadline, the Annual Capacity Payment set forth in <u>Exhibit A</u> shall be adjusted to an amount equal to the actual Contract Quantity delivered for the applicable Contract Year *multiplied* by the Contract Price for the applicable Contract Year; *provided* that the foregoing shall not relieve Seller of any of its obligations as set forth in <u>Sections 4</u> and <u>6</u>.

4. <u>Failures to Deliver and/or Receive</u>.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) <u>Seller's Failure to Deliver</u>. In the event that Seller fails to deliver all or part of the Contract Quantity of the Product by the applicable Transfer Deadline (such deficient quantity being the " <u>Shortfall Delivery Quantity</u> "), and such failure is not excused by Buyer's failure to perform, then Seller shall provide Buyer with replacement ZRCs in accordance with <u>Section 6</u>. If despite Seller's use of commercially reasonable efforts Seller is unable to provide Buyer with such replacement ZRCs for a Contract Year, Seller shall pay Buyer, within ten (10) Business Days of invoice receipt, an amount equal to the positive difference, if any, obtained by subtracting the Contract Price (then applicable to the Shortfall Delivery Quantity) from the Replacement Price and multiplying such positive difference, if any, by the Shortfall Delivery Quantity (such amount the " <u>Shortfall Delivery Damages</u> "); *provided, however* that Seller shall not be liable for any Capacity Deficiency Charges or penalties or charges assessed to Buyer (either directly or through contractual obligation) resulting from Seller's

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failure to deliver the Shortfall Delivery Quantity, including, without limitation, any charges, penalties or increased costs assessed against Buyer under the MISO Rules. The Parties acknowledge and agree that with respect to this Transaction only, the definition of "Replacement Price" in the Master Agreement is deleted in its entirety and replaced with the following:

"<u>Replacement Price</u>" shall mean: the price at which Buyer, acting in a commercial reasonable manner, purchases a replacement for any Product being a part of the Shortfall Delivery Quantity, or if no such purchase is made by Buyer the Auction Clearing Price, converted to a $/ZRC price, paid to the owners of Zone 6 ZRCs that cleared in the MISO capacity auction for the relevant Season of the relevant Contract Year corresponding to that portion of the Shortfall Delivery Quantity applicable to the relevant Season.

The invoice from Buyer to Seller for any amount owed by Seller to Buyer pursuant to this provision shall include a written statement explaining in reasonable detail the calculation of such amount.

If Seller fails to deliver at least 90% of the Contract Quantity for any two (2) consecutive Contract Years and Seller fails to either provide Buyer with replacement ZRCs pursuant to <u>Section 6</u> or pay Buyer the Shortfall Delivery Damages in accordance with this <u>Section 4(a)</u>, Buyer shall have the right, upon thirty (30) days' written notice to Seller, to terminate this Confirmation, and such termination shall be without prejudice to Buyer's right to recover damages for any prior Shortfall Delivery Quantities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) <u>Buyer's Failure to Receive</u>. In the event that Buyer fails to receive all or part of the Contract Quantity of the Product for a Contract Year by the applicable Transfer Deadline (such deficient quantity being the " <u>Shortfall Receipt Quantity</u> "), and such failure is not excused by Seller's failure to perform, then Buyer shall pay Seller, within ten (10) Business Days of invoice receipt, an amount equal to the positive difference, if any, obtained by subtracting the Sales Price from the Contract Price (then applicable to the Shortfall Receipt Quantity) and multiplying such positive difference, if any, by the Shortfall Receipt Quantity (such amount the " <u>Shortfall Receipt Damages</u> "). The Parties acknowledge and agree that with respect to this Transaction only, the definition of "Sales Price" in the Master Agreement is deleted in its entirety and replaced with the following:

"<u>Sales Price</u>" shall mean: the price at which Seller, acting in a commercially reasonable manner, resells any Product being a part of the Shortfall Receipt Quantity, or absent any such sale, the Auction Clearing Price, converted to a $/ZRC price, paid to the owners of Zone 6 ZRCs that cleared in the MISO capacity auction for the relevant Season of the relevant Contract Year corresponding to that portion of the Shortfall Receipt Quantity applicable to the relevant Season.

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The invoice from Seller to Buyer for any amount owed by Buyer to Seller pursuant to this provision shall include a written statement explaining in reasonable detail the calculation of such amount.

If Buyer fails to receive at least 90% of the Contract Quantity for any two (2) consecutive Contract Years and Buyer fails to pay Seller the Shortfall Receipt Damages in accordance with this <u>Section 4(b)</u>, Seller shall have the right, upon thirty (30) days' written notice to Buyer, to terminate this Confirmation, and such termination shall be without prejudice to Seller's right to recover damages for any prior Shortfall Receipt Quantities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) <u>Limitation of Remedies</u>. The Parties acknowledge and agree that the remedies set forth in this <u>Section 4</u> regarding failures to deliver/receive shall supersede and replace the remedies for failure to deliver/receive set forth in the Master Agreement with respect to this Transaction only and shall be the sole and exclusive remedy available to each of Buyer and Seller in the case of a failure to deliver/receive.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) <u>Shortfall Notice</u>. Within ten (10) Business Days after the final UCAP/ISAC ratio and SAC values for Schedule 53 resources are posted on the MECT, if Seller anticipates there will be a Shortfall Delivery Quantity in any Contract Year which Seller is not otherwise able to replace in accordance with Section 4(a) prior to the applicable Transfer Deadline, Seller shall provide written notice thereof to Buyer and Buyer shall, in its discretion, replace any Shortfall Delivery Quantity and invoice Seller with respect to any applicable Shortfall Delivery Damages in accordance with Section 4(a).

5. <u>MISO Recalculation of Accredited Capacity</u>.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) <u>Recalculation</u>. If at any time during the Term MISO recalculates the available Accredited Capacity for either of the Units for any Season of a Contract Year as a direct result of a Change-in-Law or Force Majeure (a " <u>MISO AC Recalculation</u> ") and such MISO AC Recalculation results in a reduction of the overall Zone 6 ZRCs available from the Units in any Contract Year during the Delivery Term, the Contract Quantity in any such Contract Year may, at Seller's option and in Seller's sole discretion, be reduced on a basis equivalent to the proportional reduction of all Zone 6 ZRCs previously available to the Units for any such Contract Year (or, as applicable, Season of a Contract Year) (*e.g*. if the available Accredited Capacity of the Units is reduced by 10%, the Contract Quantity may be reduced by 10%) (the quantity of reduced Zone 6 ZRCs being the " <u>Recalculation Reduction Quantity</u> "). Any such reduction of the Contract Quantity by the Recalculation Reduction Quantity for any applicable Season or Contact Year shall not (i) be deemed to be an Event of Default by Seller, (ii) be deemed to create for such Contract Year any Shortfall

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Delivery Quantity for which Buyer is entitled to any payment from Seller under the provisions of <u>Section 4(a)</u> above, or (iii) modify the Contract Price payable by Buyer for the applicable Contract Quantity, as so reduced by the Recalculation Reduction Quantity.

6. <u>Replacement ZRCs/Non-Zone 6 ZRCs.</u>

Relative to any Shortfall Delivery Quantity or Recalculation Reduction Quantity, Seller shall satisfy any such Shortfall Delivery Quantity or Recalculation Reduction Quantity from any Surplus Quantity ZRCs (as defined below) available from Merom Generation Station, and if Seller is unable to fully satisfy such Shortfall Delivery Quantity or Recalculation Reduction Quantity from such Surplus Quantity ZRCs, Seller shall have the right at its option in its sole discretion to satisfy any remaining Shortfall Delivery Quantity or Recalculation Reduction Quantity from any one or more alternate Generation Resources located within Zone 6, or to acquire ZRCs for Zone 6 through the PRA for the applicable Contract Year or Season for which any such Shortfall Delivery Quantity or Recalculation Reduction Quantity has been determined; *provided, however,* that Seller shall not acquire more than fifteen percent (15%) of the Shortfall Delivery Quantity or Recalculation Reduction Quantity by acquiring ZRCs from a MISO Local Resource Zone other than Zone 6, whether acquired from MISO (though the PRA for the applicable Contract Year or Season) or from an alternate Generation Resource located in such other MISO Local Resources Zone (all such other Local Resource Zone ZRCs being "<u>Non-Zone 6 ZRCs</u>"). In all cases where Seller acquires Non-Zone 6 ZRCs, Seller will be responsible for all costs and expenses associated with the acquisition and transfer of Non-Zone 6 ZRCs to Buyer, including all costs and expenses charged or assessed by MISO for the qualification of Non-Zone 6 ZRCs as Zone 6 ZRCs. All such Zone 6 ZRCs or Non-Zone 6 ZRCs shall, no later than ten (10) days preceding the deadline for submission of Fixed Resource Adequacy Plans (as defined in the MISO Rules) for the applicable Contract Year, be delivered to Buyer by Seller submitting the transaction(s) in MISO's MECT system (or any successor system) to electronically assign all such ZRCs to Buyer. Seller shall provide Buyer with written notice of (i) its intent to procure replacement ZRCs, (ii) the source and quantity of such replacement ZRCs, and (iii) the anticipated delivery date for such replacement ZRCs, in each case no later than twelve (12) Business Days prior to the deadline for submission of Fixed Resource Adequacy Plans (as defined in the MISO Rules) for the applicable Contract Year.

"<u>Surplus Quantity ZRCs</u>" means the aggregate amount of Zone 6 ZRCs available from the Units that exceeds the sum of (i) the applicable Contract Quantity to be delivered to Buyer under this Confirmation for such Contract Year or Season thereof, as applicable, plus (ii) the applicable quantity of Product that Seller has agreed in writing to sell and deliver to third parties during such Contract Year or Season thereof, as applicable.

7. <u>Change-in-Law.</u>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) <u>Occurrence of a Change-in-Law</u>. If a Change-in-Law occurs that results in the elimination of, or otherwise has a material adverse impact on the a

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material right or obligation of a Party hereunder, other than a Change-in-Law that results in a MISO AC Recalculation, then, within a reasonable amount of time following written notice thereof by a Party, the Parties shall negotiate in good faith in an attempt to amend this Confirmation to restore or maintain for each Party as nearly as possible, the intent and substance of the economic bargain reached by the Parties prior to such change. If after negotiating in good faith in accordance with the foregoing, the Parties are unable to reach agreement as to how to amend this Confirmation, either Party may terminate this Transaction by delivering written notice to the other Party designating a date no earlier than ten (10) days from the date of such written notice on which this Confirmation and Transaction shall terminate, which termination shall not result in any liability of either Party for any payments or obligations due to be paid or performed after the date of such termination other than those that have accrued or accrue with respect to any period or performance rendered prior to the date of such termination. For the avoidance of doubt, the date of termination under this <u>Section 7</u> shall not be deemed an Early Termination Date under the Master Agreement.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) <u>Definitions</u>.

"<u>Change-in-Law</u>" means the occurrence, at any time during the Term, but prior to the delivery of and payment for the Contract Quantity in a Contract Year, of: (a) the adoption, imposition, amendment, repeal, promulgation, change in interpretation or modification by a Governmental Authority of any law, rule or regulation, or the issuance of a final and non-appealable order, judgment, award or decree of a Governmental Authority with jurisdiction over the Transaction or a Party hereto having the effect of the foregoing, or (b) the adoption, imposition, amendment, repeal, promulgation, change in interpretation or modification by MISO of any new rule or change to an existing MISO Rule that is applicable to the implementation of any provision of this Transaction.

"<u>Governmental Authority</u>" means any national, state, provincial, local or municipal government, any political subdivision thereof or any other governmental, regulatory, quasi-governmental, judicial, public or statutory instrumentality, authority, body, agency, department, bureau, or entity (i) with authority to bind a Party at law or (ii) lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, policy, regulatory or taxing authority or power; *provided*, *however*, that "Governmental Authority" shall not in any event include any Party or any Affiliate of a Party.

8. <u>Performance Security Requirements</u>.

Each of the Parties shall provide Performance Security in accordance with <u>Exhibit B</u>.

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9. <u>Master Agreement</u>.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) This Confirmation shall be deemed to supplement, form a part of, and be subject to an agreement in the form of a 2000 Edison Electric Institute and National Energy Marketers Association Master Power Purchase & Sale Agreement, Version 2.1 (modified 4/25/00) (" <u>Master Agreement</u> "), which is hereby incorporated in its entirety by this reference as if the Parties had executed such agreement on the Execution Date; *provided* that (i) the Errata Version 1.1 published by the Edison Electric Institute with a date of July 18, 2007 shall apply (as applicable); (ii) Closeout Setoff, Option A (Section 5.6) shall apply; *provided, however*, it is recognized by the Parties that the "Non-Defaulting Party" and "Defaulting Party," each as defined in the Master Agreement, only refers to Buyer and Seller and does not include and shall not be deemed to include any one or more of the Affiliates of either Buyer or Seller; and (iii) Confidentiality (Section 10.11) shall apply, *provided however*, that a Party may disclose any one or more of the commercial terms of this Transaction (A) as deemed appropriate to report net power costs or other information to regulators and market monitors and (B) other than the name of the other Party unless otherwise agreed to in writing by the Parties, to any industry price source for the purpose of aggregating and reporting such information in the form of a published energy price index. All notices, requests, statements or payments under the Master Agreement or this Confirmation shall be made as specified on <u>Exhibit C</u> attached hereto.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) In addition, the definition of "Force Majeure" Section 1.23 included in the Master Agreement shall be deleted and replaced in its entirety with the following:

"Force Majeure" means an event or circumstance which prevents one Party from performing its obligations under this Transaction, which event or circumstance was not anticipated as of the Execution Date, which is not within the reasonable control of, or the result of the negligence of, the Claiming Party, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided. Force Majeure shall not be based on (i) the loss of Buyer's markets; (ii) Buyer's inability economically to use or resell the Product purchased hereunder; (iii) the loss or failure of Seller's supply; (iv) Seller's ability to sell the Product at a price greater than the Contract Price, or (v) failure or breakdown of mechanical equipment except to the extent that such failures or breakdowns were due to circumstances that would constitute Force Majeure. Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point and (ii) such curtailment is due to "force majeure" or "uncontrollable force" or a similar term as defined under the Transmission Provider's tariff; provided, however, that existence of the

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foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred. The applicability of Force Majeure to the Transaction is governed by the terms of the Products and Related Definitions contained in Schedule P."

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) In addition, the following provision shall be included in the Master Agreement as Section 10.12:

"<u>FERC Standard of Review; Mobile-Sierra Waiver</u>.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) Absent the agreement of all Parties to the proposed change, the standard of review for changes to any rate, charge, classification, term or condition of this Agreement, whether proposed by a Party (to the extent that any waiver in subsection (b) below is unenforceable or ineffective as to such Party), a non-party or FERC acting *sua sponte*, shall solely be the "public interest" application of the "just and reasonable" standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) and clarified inter alia in Morgan Stanley Capital Group, Inc. v. Pub. Util. Dist. No. 1 of Snohomish, 128 S. Ct. 2733, 171 L. Ed. 2d 607 (2008) and NRG Power Mktg., LLC v. Me. Pub. Utils. Comm'n, 130 S. Ct. 693, 78 U.S.L.W. 4038 (2010) (the "<u>Mobile-Sierra</u>" doctrine).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) In addition, and notwithstanding the foregoing subsection (a), to the fullest extent permitted by applicable law, each Party, for itself and its successors and assigns, hereby expressly and irrevocably waives any rights it can or may have, now or in the future, whether under §§ 205 and/or 206 of the Federal Power Act or otherwise, to seek to obtain from FERC by any means, directly or indirectly (through complaint, investigation or otherwise), and each hereby covenants and agrees not at any time to seek to so obtain, an order from FERC changing any section of this Agreement specifying the rate, charge, classification, or other term or condition agreed to by the Parties, it being the express intent of the Parties that, to the fullest extent permitted by applicable law, neither Party shall unilaterally seek to obtain from FERC any relief changing the rate, charge, classification, or other term or condition of this Agreement, notwithstanding any subsequent changes in applicable law or market conditions that may occur. In the event it were to be determined that applicable law precludes the Parties from waiving their rights to seek changes from FERC to their market-based power sales contracts (including entering into covenants not to do so) then this subsection (b) shall not apply, provided that, consistent with the foregoing subsection (a), neither Party shall seek any such changes except solely under the "public interest" application of the "just and reasonable" standard of review and otherwise as set forth in the foregoing section (a)."

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10. <u>Indemnity of MISO Charges or Penalties</u>.

Notwithstanding the foregoing or any other provision that would otherwise limit a Party's liability under the Master Agreement, if a Party is required to pay any Charges or Penalties assessed by MISO which are the responsibility of the other Party under the MISO Rules (the "<u>Responsible Party</u>"), such Responsible Party shall indemnify and hold harmless the other Party (the "<u>Indemnified Party</u>") from any such amounts; *provided, however*, notwithstanding the fact that the Responsible Party is responsible for any such Charges or Penalties, the foregoing indemnity will not be applicable where any such Charges or Penalties are assessed by MISO as a result of the negligence or willful misconduct of the Indemnified Party. For purposes of this <u>Section 10</u>, "<u>Charges or Penalties</u>" means any charges or penalties billed by MISO to a Party with respect to the Product, the performance of a Generation Resource associated with the Product or the performance of the Parties within MISO.

11. <u>Limitations on Liability</u>.

Under no circumstances shall Seller have any liability to Buyer or NIPSCO under the Buyer-NIPSCO Agreement due to Buyer's failure or inability to provide Product to NIPSCO thereunder due to, arising out of or resulting from any failure by Seller to perform its obligations hereunder.

12. <u>Governing Law</u>.

Notwithstanding the terms of the Master Agreement to the contrary, this Confirmation shall be governed by, interpreted and enforced in accordance with the laws of the State of Indiana, without regard to conflict of law principles.

13. <u>Jurisdiction/Venue</u>.

Notwithstanding the terms of the Master Agreement to the contrary, all litigation arising out of, or relating to this Confirmation, shall be brought in the federal or state courts in Indianapolis, Indiana, and each Party agrees to commence any such action only in such courts. The Parties irrevocably agree to submit to the exclusive jurisdiction of such courts and waive any defense of forum non conveniens. The service of any process, summons, notice or document by U.S. registered mail to a Party's address set forth herein shall be effective service of process for any such action or proceeding. Each Party irrevocably and unconditionally waives any objection to the laying of venue of any action or proceeding arising out of this Confirmation in such courts, and hereby irrevocably and unconditionally waives and agrees not to plead or claim in any such court that an action brought in any such court has been brought in an inconvenient forum.

14. <u>Waiver of Jury Trail</u>.

TO THE EXTENT PERMITTED BY APPLICABLE LAW, EACH PARTY TO THIS CONFIRMATION HEREBY EXPRESSLY WAIVES ANY RIGHT TO TRIAL BY

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JURY OF ANY CLAIM, DEMAND, ACTION OR CAUSE OF ACTION ARISING UNDER OR IN ANY WAY CONNECTED WITH OR RELATED OR INCIDENTAL TO THE DEALINGS OF THE PARTIES HERETO, OR THE TRANSACTION SET OUT HEREIN, IN EACH CASE WHETHER NOW EXISTING OR HEREAFTER ARISING, AND WHETHER FOUNDED IN CONTRACT OR TORT OR OTHERWISE; AND EACH PARTY HEREBY AGREES AND CONSENTS THAT ANY SUCH CLAIM, DEMAND, ACTION OR CAUSE OF ACTION SHALL BE DECIDED BY COURT TRIAL WITHOUT A JURY, AND THAT ANY PARTY TO THIS CONFIRMATION MAY FILE AN ORIGINAL COUNTERPART OR A COPY OF THIS <u>SECTION 14</u> WITH ANY COURT AS WRITTEN EVIDENCE OF THE CONSENT OF THE SIGNATORIES HERETO TO THE WAIVER OF THEIR RIGHT TO TRIAL BY JURY.

15. <u>Permitted Transfers</u>.

Seller shall not undergo or facilitate a Material Change without Buyer's prior written consent (not to be unreasonably withheld or delayed); *provided, howeve*r, that Buyer's consent shall not be required for any Material Change that results in (i) Seller being Controlled by a Permitted Transferee, or (ii) all or substantially all of the assets of Seller related to the Merom Generation Station being owned, maintained and operated by a Permitted Transferee. Any Material Change effectuated in violation of this <u>Section 15</u> shall constitute an Event of Default by Seller. For purposes of this Confirmation:

"<u>Material Change</u>" means either (i) any transfer, assignment or acquisition of the ownership of more than fifty percent (50%) of the equity of, or any other ownership interest in, Seller, or (ii) any transfer, assignment or acquisition of all or substantially all of the assets of Seller related to the Merom Generation Station in a single transaction or a series of transactions.

"<u>Control</u>" means with respect to any Person, the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person whether through ownership of fifty percent (50%) or more of the voting stock of such Person, by agreement or otherwise.

"<u>Permitted Transferee</u>" means a Person that (a) as of the date of the Execution Date is at least as creditworthy as Seller, (b) individually or together with its Affiliates meets the definition of a Qualified Operator or engages a Qualified Operator to manage, maintain and operate the Merom Generation Station, and (c) agrees in writing to assume Seller's right and obligations under this Confirmation, as applicable, and agrees in writing to be bound by the terms and conditions of this Confirmation, including but not limited to assuming Seller's Performance Security obligations set forth in <u>Exhibit B.</u>

"<u>Person</u>" means a natural person, corporation, limited liability company, electric cooperative, partnership, trust, association, joint venture, real estate investment trust or business trust (including any beneficiary thereof), unincorporated association, municipal corporation, municipally-owned utility, municipality or other governmental authority, and any other form of business or legal entity.

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"<u>Qualified Operator</u>" means a Person that has at least three (3) years of experience operating utility-scale projects of fossil-fuel powered generation facilities similar to the Merom Generation Station that are in excess of 350 MW in capacity.

**[SIGNATURE PAGE FOLLOWS]**

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***Execution Copy***

IN WITNESS WHEREOF, each of the Parties intending to be legally bound by the provisions of this Confirmation, has caused its duly authorized representatives to execute this Confirmation.

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| | |
|:---|:---|
| &nbsp;&nbsp;**BUYER:** | &nbsp;&nbsp;**SELLER:** |
| &nbsp;&nbsp;**NIPSCO GENERATION, LLC** | &nbsp;&nbsp;**Hallador Power Company, LLC** |
| &nbsp;&nbsp;<br>**By:/s/DANIEL L. DOUGLAS**<br>**Name:Daniel L. Douglas**<br>**Title:President and COO** | &nbsp;&nbsp;**<br>By:/s/HEATH A. LOVELL**<br>**Name:Heath A. Lovell**<br>**Title:President** |

---

[*Signature Page to Long-Form Confirmation Letter*]

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**Exhibit A**

**Contract Quantity/Contract Price/Annual Capacity Payment** 

**Certain identified information has been excluded from this exhibit both because it (i) is not material and (ii) is the type that Hallador Energy Company treats as private or confidential. Brackets with triple asterisks denote omissions.**

[\*\*\*]

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**Exhibit B**

**Performance Security Requirements** 

**Certain identified information has been excluded from this exhibit both because it (i) is not material and (ii) is the type that Hallador Energy Company treats as private or confidential. Brackets with triple asterisks denote omissions.**

[\*\*\*]

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**Exhibit C**

**Notice Information**

**Certain identified information has been excluded from this exhibit both because it (i) is not material and (ii) is the type that Hallador Energy Company treats as private or confidential. Brackets with triple asterisks denote omissions.**

[\*\*\*]

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## Exhibit 31.1

**Exhibit 31.1**

CERTIFICATION

I, Brent K. Bilsland, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Hallador Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

---

| | |
|:---|:---|
| May 6, 2026 | /s/ BRENT K. BILSLAND |
|  | Brent K. Bilsland, Chairman, President and CEO |

---

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## Exhibit 31.2

**Exhibit 31.2**

CERTIFICATION

I, Todd E. Telesz, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Hallador Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

---

| | |
|:---|:---|
| May 6, 2026 | /s/ TODD E. TELESZ |
|  | Todd E. Telesz, CFO |

---

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## Exhibit 31.3

**Exhibit 31.3**

CERTIFICATION

I, Eric Van Deman, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Hallador Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

---

| | |
|:---|:---|
| May 6, 2026 | /s/ ERIC VAN DEMAN |
|  | Eric Van Deman, CAO |

---

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## Ex-32

**Exhibit 32**

CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report (the "Report"), of Hallador Energy Company (the "Company"), on Form 10-Q for the period ended March 31, 2026 as filed with the Securities and Exchange Commission on the date hereof the undersigned, in the capacities and date indicated below, each hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

---

| | | |
|:---|:---|:---|
| May 6, 2026 | By: | /s/ BRENT K. BILSLAND |
|  |  | Brent K. Bilsland, Chairman, President and CEO |
|  | By: | /s/TODD E. TELESZ |
|  |  | Todd E. Telesz, CFO |
|  |  | /s/ERIC VAN DEMAN |
|  |  | Eric Van Deman, CAO |

---

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate document. A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

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## Exhibit 95.1

**Exhibit 95.1**

**MINE SAFETY DISCLOSURES**

Our principles at Sunrise Coal LLC are safety, honesty, and compliance. We firmly believe that these values compose a dedicated workforce and with that, come high production. The core to this is our strong training programs that include accident prevention, workplace inspection and examination, emergency response and compliance. We work with the Federal and State regulatory agencies to help eliminate safety and health hazards from our workplace and increase safety and compliance awareness throughout the mining industry.

We are regulated by the Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 ("Mine Act"). MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. We present information below regarding certain violations which MSHA has issued with respect to our mines. While assessing this information please consider that the number and cost of violations will vary depending on the MSHA inspector and can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed.

The disclosures listed below are provided pursuant to the Dodd-Frank Act. We believe that the following disclosures comply with the requirements of the Dodd-Frank Act; however, it is possible that future SEC rule making may require disclosures to be filed in a different format than the following.

The table that follows outlines required disclosures and citations/orders issued to us by MSHA during the 1<sup>st</sup> Quarter 2026. The citations and orders outlined below may differ from MSHA`s data retrieval system due to timing, special assessed citations, and other factors.

Definitions:

*Section 104(a) Significant and Substantial Citations "S&S":* An alleged violation of a mining safety or health standard or regulation where there exists a reasonable likelihood that the hazard outlined will result in an injury or illness of a serious nature.

*Section 104(b) Orders: Failure* to abate a 104(a) citation within the period of time prescribed by MSHA. The result of which is an order of immediate withdraw of non-essential persons from the affected area until MSHA determines the violation has been corrected.

*Section 104(d) Citations and Orders:* An alleged unwarrantable failure to comply with mandatory health and safety standards.

*Section 107(a) Orders:* An order of withdrawal for situations where MSHA has determined that an imminent danger exists. 

*Section 110(b)(2) Violations:* An alleged flagrant violation issued by MSHA under section 110(b)(2) of the Mine Act.

*Pattern or Potential Pattern of Violations:* A pattern of violations of mandatory health or safety standards that are of such a nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of the Mine Act or a potential to have such a pattern.

*Contest of Citations, Orders, or Proposed Penalties:* A contest proceeding may be filed with the Commission by the operator or miners/miner's representative to challenge the issuance or penalty of a citation or order issued by MSHA.

*MSHA Federal Mine ID#`s:*

*(12-02465 – Carlisle Preparation Plant)*

*(12-02394 – Oaktown Fuels No. 1)*

*(12-02418 – Oaktown Fuels No. 2)* 

*(12-02462 – Oaktown Fuels Preparation Plant)*

*(12-02249 – Prosperity Mine)*

*(12-02339 Freelandville East, Center Pit Mine)*

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![Graphic](hnrg-20260331xex95d1001.jpg)

![Graphic](hnrg-20260331xex95d1002.jpg)

![Graphic](hnrg-20260331xex95d1003.jpg)

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