# EDGAR Filing Document

**Accession Number:** 0001696088
**File Stem:** 0001185185-25-000956
**Filing Date:** 2025-8
**Character Count:** 103437
**Document Hash:** 563834125427a3c19b9afeb111616db4
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001185185-25-000956.hdr.sgml**: 20250813

**ACCESSION NUMBER**: 0001185185-25-000956

**CONFORMED SUBMISSION TYPE**: 10-Q

**PUBLIC DOCUMENT COUNT**: 45

**CONFORMED PERIOD OF REPORT**: 20250630

**FILED AS OF DATE**: 20250813

**DATE AS OF CHANGE**: 20250813

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** ENERGY RESOURCES 12, L.P.
- **CENTRAL INDEX KEY:** 0001696088
- **STANDARD INDUSTRIAL CLASSIFICATION:** CRUDE PETROLEUM & NATURAL GAS [1311]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 814805237
- **STATE OF INCORPORATION:** DE
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-Q
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 000-55916
- **FILM NUMBER:** 251210557

**BUSINESS ADDRESS:**
- **STREET 1:** 814 EAST MAIN ST.
- **CITY:** RICHMOND
- **STATE:** VA
- **ZIP:** 23219
- **BUSINESS PHONE:** (804)344-8121

**MAIL ADDRESS:**
- **STREET 1:** 814 EAST MAIN ST.
- **CITY:** RICHMOND
- **STATE:** VA
- **ZIP:** 23219

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** Sundance Energy, L.P.
- **DATE OF NAME CHANGE:** 20170126

?xml version='1.0' encoding='ASCII'?

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 10-Q**

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

For the quarterly period ended June 30, 2025

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

FOR THE TRANSITION PERIOD FROM TO

Commission File Number 000-55916

**<u>Energy Resources 12, L.P.</u>**

(Exact name of registrant as specified in its charter)

---

| | |
|:---|:---|
| **Delaware** | **81-4805237** |
| (State or other jurisdiction<br> of incorporation or organization) | (IRS Employer<br> Identification No.) |
| **120 W 3rd Street, Suite 220<br> Fort Worth, Texas** | **76102** |
| (Address of principal executive offices) | (Zip Code) |

---

**<u>(817) 882-9192</u>**

(Registrant's telephone number, including area code)

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

---

| | | |
|:---|:---|:---|
| **Title of each class** | **Trading Symbol** | **Name of each exchange on which registered** |

---

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 Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐ Accelerated filer ☐ <br> Non-accelerated filer ☑ Smaller reporting company ☑ <br> 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 August 13, 2025, the Partnership had 11,031,579 common units outstanding.

**Energy Resources 12, L.P.**

**Form 10-Q**

**Index**

---

| | | |
|:---|:---|:---|
| | | **Page<br> Number** |
| **PART I. FINANCIAL INFORMATION** | **PART I. FINANCIAL INFORMATION** |  |
| Item 1. | [Consolidated Financial Statements (Unaudited)](#a_001) | 3 |
|  | [Consolidated Balance Sheets – June 30, 2025 and December 31, 2024](#a_002) | 3 |
|  | [Consolidated Statements of Operations – Three and six months ended June 30, 2025 and 2024](#a_003) | 4 |
|  | [Consolidated Statements of Partners' Equity – Three and six months ended June 30, 2025 and 2024](#a_004) | 5 |
|  | [Consolidated Statements of Cash Flows – Six months ended June 30, 2025 and 2024](#a_005) | 6 |
|  | [Notes to Consolidated Financial Statements](#a_006) | 7 |
| Item 2. | [Management's Discussion and Analysis of Financial Condition and Results of Operations](#a_007) | 13 |
| Item 3. | [Quantitative and Qualitative Disclosures About Market Risk](#a_008) | 20 |
| Item 4. | [Controls and Procedures](#a_009) | 20 |
| **PART II. OTHER INFORMATION** | **PART II. OTHER INFORMATION** |  |
| Item 1. | [Legal Proceeding](#a_010) | 21 |
| Item 1A. | [Risk Factors](#a_011) | 21 |
| Item 2. | [Unregistered Sales of Equity Securities and Use of Proceeds](#a_012) | 21 |
| Item 3. | [Defaults upon Senior Securities](#a_013) | 21 |
| Item 4. | [Mine Safety Disclosures](#a_014) | 21 |
| Item 5. | [Other Information](#a_015) | 21 |
| Item 6. | [Exhibits](#a_016) | 21 |
| [Signatures](#a_017) | [Signatures](#a_017) | 22 |

---

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

**PART I. FINANCIAL INFORMATION**

**Item 1. Financial Statements**

**Energy Resources 12, L.P.**

**Consolidated Balance Sheets**

---

| | | |
|:---|:---|:---|
|  | **June 30, <br> 2025** | **December 31,<br> 2024** |
|  | (unaudited) | |
| **Assets** |  |  |
| &nbsp;&nbsp;&nbsp;Cash and cash equivalents | $502395 | $1463582 |
| &nbsp;&nbsp;&nbsp;Accounts receivable and other current assets | 2500484 | 3885384 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Current Assets | 3002879 | 5348966 |
| &nbsp;&nbsp;&nbsp;Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $109,241,297 and 101,131,766, respectively | 149461424 | 156140235 |
| &nbsp;&nbsp;&nbsp;Other assets, net | - | 13276 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Assets | $152464303 | $161502477 |
| **Liabilities** |  |  |
| &nbsp;&nbsp;&nbsp;Accounts payable and accrued expenses | $1604592 | $1961745 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Current Liabilities | 1604592 | 1961745 |
| &nbsp;&nbsp;&nbsp;Revolving credit facility | 6400000 | 4600000 |
| &nbsp;&nbsp;&nbsp;Asset retirement obligations | 782514 | 765443 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Liabilities | 8787106 | 7327188 |
| **Partners' Equity** |  |  |
| &nbsp;&nbsp;&nbsp;Limited partners' interest (11,031,579 common units issued and outstanding, respectively) | 143677412 | 154175504 |
| &nbsp;&nbsp;&nbsp;General partner's interest | (215) | (215) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Partners' Equity | 143677197 | 154175289 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Liabilities and Partners' Equity | $152464303 | $161502477 |

---

See notes to consolidated financial statements.

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

**Energy Resources 12, L.P.**

**Consolidated Statements of Operations**

**(Unaudited)**

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **Three Months<br> Ended**<br>**June 30, <br> 2025** | **Three Months<br> Ended**<br>**June 30, <br> 2024** | **Six months<br> ended**<br>**June 30, <br> 2025** | **Six months<br> ended**<br>**June 30, <br> 2024** |
| **Revenues** | | | | |
| &nbsp;&nbsp;&nbsp;Oil | $5240542 | 8152941 | 11563315 | 15346456 |
| &nbsp;&nbsp;&nbsp;Natural gas | 494493 | 203219 | 1277903 | 756904 |
| &nbsp;&nbsp;&nbsp;Natural gas liquids | 666982 | 729489 | 1437952 | 1665049 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total revenue | 6402017 | 9085649 | 14279170 | 17768409 |
| **Operating costs and expenses** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Production expenses | 3271318 | 4769531 | 7145603 | 9085958 |
| &nbsp;&nbsp;&nbsp;Production taxes | 470285 | 873381 | 1028732 | 1545922 |
| &nbsp;&nbsp;&nbsp;General and administrative expenses | 533466 | 479000 | 1176666 | 1176686 |
| &nbsp;&nbsp;&nbsp;Depreciation, depletion, amortization and accretion | 4350181 | 4350248 | 8126382 | 8464510 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating costs and expenses | 8625250 | 10472160 | 17477383 | 20273076 |
| **Operating loss** | (2223233) | (1386511) | (3198213) | (2504667) |
| &nbsp;&nbsp;&nbsp;Interest expense, net | (122119) | (41053) | (237733) | (36364) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total other expense, net | (122119) | (41053) | (237733) | (36364) |
| **Net loss** | $(2345352) | $(1427564) | $(3435946) | $(2541031) |
| **Basic and diluted net loss per common unit** | $(0.21) | $(0.13) | $(0.31) | $(0.23) |
| **Weighted average common units outstanding - basic and diluted** | 11031579 | 11031579 | 11031579 | 11031579 |

---

See notes to consolidated financial statements.

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

**Energy Resources 12, L.P.**

**Consolidated Statements of Partners**' **Equity**

**(Unaudited)**

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **Limited Partner** | **Limited Partner** | **General<br> Partner** | **Total<br> Partners'** |
|  | **Common Units** | **Amount** | **Amount** | **Equity** |
| **Balances - December 31, 2023** | **11031579** | $**173241229** | $**(215)** | $**173241014** |
| Distributions declared and paid to common units ($0.320541 per common unit) |  | (3536073) |  | (3536073) |
| State tax withholding payments made on behalf of limited partners |  | (673623) |  | (673623) |
| Reversal of estimated state tax withholding for limited partners |  | 644000 |  | 644000 |
| Net loss - three months ended March 31, 2024 | - | (1113467) | - | (1113467) |
| **Balances - March 31, 2024** | **11031579** | **168562066** | **(215)** | **168561851** |
| Distributions declared and paid to common units ($0.320541 per common unit) |  | (3536073) |  | (3536073) |
| Net loss - three months ended June 30, 2024 | - | (1427564) |  | (1427564) |
| **Balances - June 30, 2024** | **11031579** | $**163598429** | $**(215)** | $**163598214** |
| **Balances - December 31, 2024** | **11031579** | $**154175504** | $**(215)** | $**154175289** |
| Distributions declared and paid to common units ($0.320541 per common unit) |  | (3536073) |  | (3536073) |
| Net loss - three months ended March 31, 2025 | - | (1090594) | - | (1090594) |
| **Balances - March 31, 2025** | **11031579** | **149548837** | **(215)** | **149548622** |
| Distributions declared and paid to common units ($0.320541 per common unit) |  | (3536073) |  | (3536073) |
| State tax withholding payments made on behalf of limited partners |  | (125000) |  | (125000) |
| Reversal of estimated state tax withholding for limited partners |  | 135000 |  | 135000 |
| Net loss - three months ended June 30, 2025 |  | (2345352) |  | (2345352) |
| **Balances - June 30, 2025** | **11031579** | $**143677412** | $**(215)** | $**143677197** |

---

See notes to consolidated financial statements.

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

**Energy Resources 12, L.P.**

**Consolidated Statements of Cash Flows**

**(Unaudited)**

---

| | | |
|:---|:---|:---|
|  | **Six months<br> ended**<br>**June 30, <br> 2025** | **Six months<br> ended**<br>**June 30, <br> 2024** |
| **Cash flow from operating activities:** | | |
| Net loss | $(3435946) | $(2541031) |
| Adjustments to reconcile net loss to cash from operating activities: |  |  |
| Depreciation, depletion, amortization and accretion | 8126382 | 8464510 |
| Changes in operating assets and liabilities: |  |  |
| Accounts receivable and other current assets | 1398176 | 498681 |
| Accounts payable and accrued expenses | (491048) | (980604) |
| Net cash flow provided by operating activities | 5597564 | 5441556 |
| **Cash flow from investing activities:** |  |  |
| Additions to oil and natural gas properties | (1161604) | (1011975) |
| Net cash flow used in investing activities | (1161604) | (1011975) |
| **Cash flow from financing activities:** |  |  |
| Cash paid for loan costs |  | (138271) |
| Proceeds from revolving credit facility | 1800000 | 2700000 |
| Payments for state withholding taxes on behalf of limited partners | (125000) |  |
| Distributions paid to limited partners | (7072147) | (7072146) |
| Net cash flow used in financing activities | (5397147) | (4510417) |
| Decrease in cash and cash equivalents | (961187) | (80836) |
| Cash and cash equivalents, beginning of period | 1463582 | 1455619 |
| Cash and cash equivalents, end of period | $502395 | $1374783 |
| Interest paid | $191400 | $- |
| Supplemental non-cash information: |  |  |
| Accrued capital expenditures related to additions to oil and natural gas properties | $498703 | $1118871 |

---

See notes to consolidated financial statements.

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

**Energy Resources 12, L.P.**

**Notes to Consolidated Financial Statements**

**June 30, 2025**

**(Unaudited)**

**Note 1. Partnership Organization**

Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the "Partnership") is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

As of June 30, 2025, the Partnership owned an approximate 5% non-operated working interest in 450 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the "Bakken Assets"). The Partnership also owns an estimated approximate 5% non-operated working interest in two wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by third-party operators on behalf of the Partnership and other working interest owners.

The general partner of the Partnership is Energy Resources 12 GP, LLC (the "General Partner"). The General Partner manages and controls the business affairs of the Partnership.

The Partnership's fiscal year ends on December 31.

**Note 2. Summary of Significant Accounting Policies**

*Basis of Presentation*

The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles ("GAAP") in the United States for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership's audited December 31, 2024 financial statements included in its 2024 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2025 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2025.

*Segment Information*

The Partnership has identified only one reportable business segment, which as a non-operated interest owner of the Bakken Assets, is the production and sale of oil, natural gas and NGLs. All of the Partnership's operations and assets are located in North Dakota, and substantially all of its revenues are attributable to United States customers.

The operating results of the Partnership's single reportable segment are evaluated by the General Partner's Chief Executive Officer, who has been determined to be the Partnership's Chief Operating Decision Maker ("CODM"), to make key operating decisions, such as the allocation of resources and the evaluation of operating segment performance. The primary measure of profit and loss evaluated by the Partnership's CODM for its single reportable segment is net income. Net income, total assets and all significant segment expense items are presented in the Partnership's consolidated financial statements and notes to the consolidated financial statements.

*Cash and Cash Equivalents*

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

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

*Use of Estimates*

The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

*Reclassifications*

Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners' equity or cash flows.

*Revenue Recognition*

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership's proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership's operators are accrued in Accounts Receivable and other current assets in the consolidated balance sheets. Variances between the Partnership's estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

*Accounts Receivable and Concentration of Credit Risk*

Substantially all of the Partnership's accounts receivable are due from the operators of the Partnership's oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership's overall exposure to credit risk, in that the purchasers of the Partnership's oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At June 30, 2025 and December 31, 2024, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible and the Partnership's operators do not have a history of non-payment. For the quarter ended June 30, 2025, approximately 93% of the Partnership's total revenue was generated through sales by five of its operators, respectively. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

*Income Tax*

The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. In mid-2022, the Partnership was contacted by the state of North Dakota, which asserted that the Partnership has an obligation to make tax payments on behalf of certain non-resident partners. In accordance with its settlements with the state of North Dakota, the Partnership made payments of (i) approximately $365,000 (approximately $0.033 per common unit) in May 2023 for tax year 2021; (ii) approximately $532,000 (approximately $0.048 per common unit) in April 2024 for tax year 2022; (iii) approximately $142,000 (approximately $0.013 per common unit) in April 2024 for tax year 2023; and (iv) approximately $125,000 (approximately $0.011 per common unit) in April 2025 for tax year 2024.

The Partnership's income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners. The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

*Fair Value of Other Financial Instruments*

The carrying value of the Partnership's other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, reflect these items' cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

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

*Net Loss Per Common Unit*

Basic net loss per common unit is computed as net loss divided by the weighted average number of common units outstanding during the period. Diluted net loss per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and six months ended June 30, 2025 and 2024. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights, as defined below, are not included in net loss per common unit until such time that it is probable Payout (as discussed in Note 6) will occur.

*Recently Issued Accounting Standards*

In November 2024, the Financial Accounting Standards Board issued Accounting Standard Update ("ASU") No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This standard requires that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The Partnership is currently evaluating this ASU to determine its impact on the Partnership's financial statements and related disclosures.

**Note 3. Oil and Gas Investments**

On February 1, 2018, the Partnership completed its first purchase ("Acquisition No. 1") in the Bakken Assets for approximately $90.5 million, including all closing costs and assumed liabilities. On August 31, 2018, the Partnership completed its second purchase of an additional non-operated working interest in the Bakken Assets for approximately $81.3 million, including all closing costs and assumed liabilities. As of June 30, 2025, the Partnership's ownership of the Bakken Assets consisted of an approximate 5% non-operated working interest in 450 producing wells, and an estimated approximate 5% non-operated working interest in two wells in various stages of the drilling and completion process.

From September 1, 2017, the effective date of Acquisition No. 1, to June 30, 2025, the Partnership has participated in the drilling of 251 wells, of which 247 have been completed as of June 30, 2025. The Partnership incurred approximately $1.4 million and $1.7 million in capital drilling and completion costs for the six-month periods ended June 30, 2025 and 2024, respectively. The Partnership anticipates less than $1 million of capital expenditures will be incurred to complete the two wells in process as of June 30, 2025. Estimated capital expenditures to complete these two wells could be significantly different from amounts actually invested, and the timing of these expenditures is difficult to estimate.

**Note 4. Debt**

On May 2, 2024, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement ("Loan Agreement") with BancFirst (the "Lender"), which provides for a revolving credit facility ("Credit Facility") with an approved maximum credit amount ("Maximum Credit Amount") of $20 million, subject to borrowing base restrictions. The Partnership paid one-time commitment and setup fees totaling $100,000 at closing. Total loan costs were approximately $146,000, which were capitalized and will be amortized through the maturity date. The maturity date was March 1, 2026. The Partnership is also subject to an additional fee of 0.50% on any incremental increase to the borrowing base. The Partnership is required to pay an unused facility fee of 0.25% on the unused portion of the Credit Facility, based on borrowings outstanding during a quarter.

Under the Loan Agreement, the initial, and current, borrowing base is $10 million. The borrowing base is subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender's analysis of the Partnership's proven oil and natural gas reserves. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.50%.

Any further advances under the Credit Facility are to be used to fund capital expenditures for the development of the Partnership's undrilled acreage. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 80% of the Partnership's producing wells. In addition, the Partnership is not required to maintain a risk management program to manage the commodity price risk of the Partnership's future oil and natural gas production. However, if the Partnership does elect to speculatively trade and hedge future oil and natural gas production, hedged volumes may not exceed 85% of the Partnership's anticipated future production.

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

The Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants include:

● A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.0

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00

The Partnership is permitted to make distributions to its limited partners so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. The Partnership was not in compliance with its debt service coverage ratio as defined within the BF Loan Agreement at December 31, 2024, March 31, 2025 and June 30, 2025. The Lender waived this covenant calculation for the quarters ended December 31, 2024, March 31, 2025 and June 30, 2025, and the Partnership was in compliance with its other covenants at June 30, 2025.

At June 30, 2025 and December 31, 2024, the outstanding balance on the Credit Facility was approximately $6.4 million, and the interest rate was 8.00%. At June 30, 2025 and December 31, 2024, the outstanding balance on the Credit Facility approximated the fair market value of the Credit Facility. The Partnership estimated the fair value of its credit facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

See Note 8. Subsequent Events for additional information about the first amendment to the Loan Agreement, which was executed in August 2025.

**Note 5. Asset Retirement Obligations**

The Partnership records an asset retirement obligation ("ARO") and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:

---

| | | |
|:---|:---|:---|
|  | **2025** | **2024** |
| Balance at January 1 | $765443 | $729315 |
| &nbsp;&nbsp;&nbsp;Well additions | 219 | 2591 |
| &nbsp;&nbsp;&nbsp;Accretion | 16852 | 15762 |
| &nbsp;&nbsp;&nbsp;Revisions | - | - |
| Balance at June 30 | $782514 | $747668 |

---

**Note 6. Capital Contribution and Partners**' **Equity**

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below), and has been reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

The Partnership completed its best-efforts offering of common units as of the close of business on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

Under the agreement with David Lerner Associates, Inc. (the "Managing Dealer"), the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership's best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold in the best-efforts offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).

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Prior to "Payout," which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights or the Dealer Manager Incentive Fees to the Managing Dealer until Payout occurs.

The Agreement of Limited Partnership of the Partnership (the "Partnership Agreement") provides that "Payout", which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines "Payout Accrual" as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

In June 2023, the General Partner declared and paid a special distribution to return $1.60 per common unit of capital to holders of Partnership common units. As described in Income Tax in Note 2. Summary of Significant Accounting Policies, in May 2023, April 2024 and April 2025, the Partnership paid total withholding taxes of approximately $0.11 per common unit to the state of North Dakota on behalf of its limited partners related to tax years 2021 through 2024. These withholding tax payments, along with the $1.60 per common unit special distribution to holders of its common units in June 2023, have reduced the Net Investment Amount described above by an approximate total of $1.71 per common unit.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership's assets, will be made as follows:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the "Dealer Manager Incentive Fees", 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

All items of income, gain, loss and deduction will be allocated to each Partner's capital account in a manner generally consistent with the distribution procedures outlined above.

For the three months ended June 30, 2025 and 2024, the Partnership paid distributions of $0.320541 per common unit, or $3.5 million, in both periods. For the six months ended June 30, 2025 and 2024, the Partnership paid distributions $0.641082 per common unit, or $7.1 million, in both periods.

As disclosed in Note 8. Subsequent Events, distributions to limited partners were suspended by the General Partner in July 2025. Therefore, the Partnership will accumulate all unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are to be paid before final Payout occurs, as defined above.

**Note 7. Related Parties**

The Class A voting members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and David S. McKenney, Chief Financial Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. ("Energy 11"), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States.

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm's length and the results of the Partnership's operations may be different than if conducted with non-related parties. The General Partner's Board of Directors oversees and reviews the Partnership's related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.

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The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include costs for organizing the Partnership, costs incurred in the offering of the common units and general and administrative costs. The Partnership also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the Partnership Agreement, subsequent to the Partnership's first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. The management fee that has been paid to the General Partner for the three and six months ended June 30, 2025 and 2024 was approximately $273,000 and $545,000 in both periods, and is included in General and administrative expenses on the consolidated statements of operations.

For the three and six months ended June 30, 2025, approximately $78,000 and $167,000 of general and administrative costs, respectively, were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At June 30, 2025, approximately $78,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses in the consolidated balance sheets. For the three and six months ended June 30, 2024, approximately $74,000 and $152,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

**Note 8. Subsequent Events**

In July 2025, the Board of Directors of the General Partner elected to suspend distributions to Partnership limited partners. The Partnership will accumulate unpaid distributions at an annualized return of seven percent (7%), and all accumulated distributions are required to be paid before final Payout occurs, as defined in the Partnership's limited partnership agreement.

The Partnership and its Lender entered into an amendment ("First Amendment") to the Loan Agreement, effective August 8, 2025 ("Effective Date"), that renewed and extended the Credit Facility for an additional year to March 1, 2027 ("Revised Maturity Date"). Key terms and conditions of the First Amendment include:

● As of the Effective Date, the borrowing base of the Credit Facility was, and remains, $10,000,000.

● The Partnership paid a loan renewal fee to the Lender associated with the First Amendment of $50,000.

● The Debt Service Coverage Ratio has been amended to be a quarter-based calculation, as opposed to a trailing 12-month calculation that was previously in effect, and will be effective starting with the quarter ended September 30, 2025.

● A negative covenant has been added that restricts the Partnership's ability to make future distributions to its limited partners if that said distribution would create an event of default under the Loan Agreement.

All other terms and conditions of the BF Loan Agreement and its subsequent amendments remain in effect.

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**Item 2. Management**'**s Discussion and Analysis of Financial Condition and Results of Operations.**

Certain statements within this report may constitute forward-looking statements. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. You can identify these statements by the use of words such as "may," "will," "could," "anticipate," "believe," "estimate," "expect," "intend," "predict," "continue," "further," "seek," "plan" or "project" and variations of these words or comparable words or phrases of similar meaning.

These forward-looking statements include such things as:

● any impact of the ongoing Russian-Ukrainian and Middle Eastern conflicts on the global energy markets;

● references to future success in the Partnership's drilling and marketing activities;

● the Partnership's business strategy;

● estimated future distributions;

● estimated future capital expenditures;

● sales of the Partnership's properties and other liquidity events;

● competitive strengths and goals; and

● other similar matters.

These forward-looking statements reflect the Partnership's current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the Partnership's control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under "Risk Factors" in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2024 and the following:

● that the Partnership's development of its properties may not be successful or that its operations on such properties may not be successful;

● general economic, market, or business conditions;

● changes in local, state, and federal laws, regulations or policies that may affect the Partnership or the oil and natural gas industry as a whole (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs);

● the risk that the wells in which the Partnership acquired an interest are productive, but do not produce enough revenue to return the investment made;

● the risk that the wells the Partnership drills do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected on the productive life of wells is shorter than expected;

● current credit market conditions and the Partnership's ability to obtain long-term financing or refinancing debt for the Partnership's drilling and acquisition activities in a timely manner and on terms that are consistent with what the Partnership projects;

● uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and

● the risk that any hedging policy the Partnership employs to reduce the effects of changes in the prices of the Partnership's production will not be effective.

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Although the Partnership believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, the Partnership cannot assure investors that its expectations will be attained or that any deviations will not be material. Investors are cautioned that forward-looking statements speak only as of the date they are made and that, except as required by law, the Partnership undertakes no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section.

The following discussion and analysis should be read in conjunction with the Partnership's Unaudited Consolidated Financial Statements and Notes thereto, appearing elsewhere in this Quarterly Report on Form 10-Q, as well as the information contained in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2024.

**Overview**

Energy Resources 12, L.P. (the "Partnership") was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership began offering common units of limited partner interest (the "common units") on a best-efforts basis on May 17, 2017, the date the Partnership's initial Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission. The Partnership completed its best-efforts offering on October 24, 2019. Total common units sold were approximately 11.0 million for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

The general partner is Energy Resources 12 GP, LLC (the "General Partner"). The General Partner manages the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner are made by the Board of Directors of the General Partner and its officers. The Partnership has no officers, directors or employees.

The Partnership was formed to acquire primarily oil and gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first asset purchase in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the "Bakken Assets"), for approximately $90.5 million. On August 31, 2018, the Partnership closed on its second asset purchase, acquiring an additional non-operated working interest in the Bakken Assets for approximately $81.3 million. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its best-efforts offering and available financing to close on the acquisitions.

As a result of these acquisitions and completed drilling during the period of ownership, as of June 30, 2025, the Partnership's ownership of the Bakken Assets consisted of an approximate 5% non-operated working interest in 450 producing wells, an estimated 5% non-operated working interest in two wells in various stages of the drilling and completion process and additional possible future development locations.

The Bakken Assets are operated by third-party operators, including Devon Energy Corporation, Marathon Oil, EOG Resources, Continental Resources and Chord Energy.

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**Current Price Environment**

Oil, natural gas and natural gas liquids ("NGL") prices are determined by many factors outside of the Partnership's control and are subject to macroeconomic market volatility. Historically, factors contributing to uncertainty within the industry include real or perceived geopolitical risks in oil-producing regions of the world, particularly Russia and the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by and production quotas set by the Organization of the Petroleum Exporting Countries ("OPEC"); and the strength of the U.S. dollar in international currency markets.

The Partnership's oil and natural gas revenues are heavily weighted to oil, so any material change to market pricing for oil has a more significant impact to the Partnership's operational performance. Oil prices declined through the first quarter of 2025 and continued into the second quarter, with oil prices closing at $57.13 per barrel on May 5, 2025 (the lowest level since the first quarter of 2021). Factors negatively impacting oil prices in 2025 include (i) confusion and uncertainty regarding U.S. trade policies and tariffs and the related concern of increased inflation; (ii) the decision by OPEC to increase its production quotas in May 2025; and (iii) global economic growth projections and the impact on global oil consumption. In July 2025, OPEC announced an additional production increase for August 2025, which could lead to further pressure on oil prices.

Significant reductions in commodity prices along with inflationary costs could impact the Partnership and its financial performance. Future growth is dependent on the Partnership's ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2025 and 2024.

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Three Months Ended June 30,** | **Three Months Ended June 30,** | | **Six Months Ended June 30,** | **Six Months Ended June 30,** | |
|  | **2025** | **2024** | **Percent**<br>**Change** | **2025** | **2024** | **Percent**<br>**Change** |
| Average market closing prices (1) |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Oil (per Bbl) | $63.87 | $80.66 | -20.8% | $67.67 | $78.81 | -14.1% |
| &nbsp;&nbsp;&nbsp;Natural gas (per Mcf) | $3.19 | $2.07 | 54.1% | $3.66 | $2.11 | 73.5% |

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(1) Based
on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas)

**Results of Operations**

In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly production in barrel of oil equivalent ("BOE") units, (2) average sales price per unit for oil, natural gas and natural gas liquids ("NGL" or "NGLs"), (3) production costs per BOE and (4) capital expenditures.

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The following table is a summary of the results from operations, including production, of the Partnership's non-operated working interest in the Bakken Assets for the three and six months ended June 30, 2025 and 2024.

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| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | **Three Months Ended June 30,** | **Three Months Ended June 30,** | **Three Months Ended June 30,** | **Three Months Ended June 30,** | | **Six Months Ended June 30,** | **Six Months Ended June 30,** | **Six Months Ended June 30,** | **Six Months Ended June 30,** | |
|  | **2025** | **Percent<br> of<br> Revenue** | **2024** | **Percent<br> of<br> Revenue** |<br>**Percent<br> Change** | **2025** | **Percent<br> of<br> Revenue** | **2024** | **Percent<br> of<br> Revenue** |<br>**Percent<br> Change** |
| Total revenues | $6402017 | 100.0% | $9085649 | 100.0% | -29.5% | $14279170 | 100.0% | $17768409 | 100.0% | -19.6% |
| Production expenses | 3271318 | 51.1% | 4769531 | 52.5% | -31.4% | 7145603 | 50.0% | 9085958 | 51.1% | -21.4% |
| Production taxes | 470285 | 7.3% | 873381 | 9.6% | -46.2% | 1028732 | 7.2% | 1545922 | 8.7% | -33.5% |
| Depreciation, depletion, amortization and accretion | 4350181 | 68.0% | 4350248 | 47.9% | 0.0% | 8126382 | 56.9% | 8464510 | 47.6% | -4.0% |
| General and administrative expenses | 533466 | 8.3% | 479000 | 5.3% | 11.4% | 1176666 | 8.2% | 1176686 | 6.6% | 0.0% |
| Sold production (BOE): |  |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Oil | 84675 |  | 97659 |  | -13.3% | 176541 |  | 199445 |  | -11.5% |
| &nbsp;&nbsp;&nbsp;Natural gas | 41898 |  | 40833 |  | 2.6% | 77557 |  | 85185 |  | -9.0% |
| &nbsp;&nbsp;&nbsp;Natural gas liquids | 39008 |  | 35978 |  | 8.4% | 69636 |  | 75199 |  | -7.4% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total | 165581 |  | 174470 |  | -5.1% | 323734 |  | 359829 |  | -10.0% |
| Average sales price per unit: |  |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Oil (per Bbl) | $61.89 |  | $80.10 |  | -22.7% | $65.50 |  | $76.95 |  | -14.9% |
| &nbsp;&nbsp;&nbsp;Natural gas (per Mcf) | 1.97 |  | 0.76 |  | 159.2% | 2.75 |  | 1.48 |  | 85.8% |
| &nbsp;&nbsp;&nbsp;Natural gas liquids (per Bbl) | 17.10 |  | 18.60 |  | -8.1% | 20.65 |  | 22.14 |  | -6.7% |
| &nbsp;&nbsp;&nbsp;Combined (per BOE) | 38.66 |  | 52.08 |  | -25.8% | 44.11 |  | 49.38 |  | -10.7% |
| Average unit cost per BOE: |  |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Production expenses | 19.76 |  | 27.34 |  | -27.7% | 22.07 |  | 25.25 |  | -12.6% |
| &nbsp;&nbsp;&nbsp;Production taxes | 2.84 |  | 5.01 |  | -43.3% | 3.18 |  | 4.30 |  | -26.0% |
| &nbsp;&nbsp;&nbsp;Depreciation, depletion, amortization and accretion | 26.27 |  | 24.93 |  | 5.4% | 25.10 |  | 23.52 |  | 6.7% |
| Capital expenditures | $741329 |  | $1170700 |  |  | $1430720 |  | $1704954 |  |  |

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***Oil, natural gas and NGL revenues***

For the three months ended June 30, 2025, revenues for oil, natural gas and NGL sales were $6.4 million. Revenues for the sale of crude oil were $5.2 million, which resulted in a realized price of $61.89 per barrel. Revenues for the sale of natural gas were $0.5 million, which resulted in a realized price of $1.97 per Mcf. Revenues for the sale of NGLs were approximately $0.7 million, which resulted in a realized price of $17.10 per BOE of production. For the three months ended June 30, 2024, revenues for oil, natural gas and NGL sales were $9.1 million. Revenues for the sale of crude oil were $8.2 million, which resulted in a realized price of $80.10 per barrel. Revenues for the sale of natural gas were $0.2 million, which resulted in a realized price of $0.76 per Mcf. Revenues for the sale of NGLs were approximately $0.7 million, which resulted in a realized price of $18.60 per BOE of production.

For the six months ended June 30, 2025, revenues for oil, natural gas and NGL sales were $14.3 million. Revenues for the sale of crude oil were $11.6 million, which resulted in a realized price of $65.50 per barrel. Revenues for the sale of natural gas were $1.3 million, which resulted in a realized price of $2.75 per Mcf. Revenues for the sale of NGLs were approximately $1.4 million, which resulted in a realized price of $20.65 per BOE of production. For the six months ended June 30, 2024, revenues for oil, natural gas and NGL sales were $17.8 million. Revenues for the sale of crude oil were $15.3 million, which resulted in a realized price of $76.95 per barrel. Revenues for the sale of natural gas were $0.8 million, which resulted in a realized price of $1.48 per Mcf. Revenues for the sale of NGLs were approximately $1.7 million, which resulted in a realized price of $22.14 per BOE of production.

Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, then decline to more consistent levels as the wells age. The Partnership's results for the three and six months ended June 30, 2025 were negatively impacted by this natural decline of aging wells; sold production for the Bakken Assets was approximately 1,800 BOE per day for the three and six months ended June 30, 2025. Sold production for the Bakken Assets was approximately 1,900 BOE per day and 2,000 BOE per day for the three and six months ended June 30, 2024.

The Partnership's results for the three and six months ended June 30, 2025 were also negatively impacted by lower market prices for oil. However, supply constraints and heightened demand due to cold winter temperatures led to sustained higher natural gas prices during the first quarter of 2025, contributing to higher Partnership natural gas revenue compared to the first half of 2024.

If the operators of the Bakken Assets are unable to produce, process and sell oil and natural gas at economical prices, the operators may curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership's oil, natural gas and NGL production, and there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion on the Partnership's investment in new wells in "Liquidity and Capital Resources" below.

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*Differentials*

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Bakken. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. On average, the Partnership's realized oil price differentials during the second quarter of 2025 decreased in comparison to the first quarter of 2025; lower differentials increase the Partnership's realized oil sales prices.

The Dakota Access Pipeline is a significant pipeline that transports oil and natural gas from North Dakota fields. Its use by operators in the region is currently in ongoing litigation in the United States. If use of the Dakota Access Pipeline or any other pipelines servicing the region are suspended at a future date, the disruption of transporting the Partnership's production out of North Dakota could negatively impact the Partnership's realized sales prices, results of operations and/or cash flows.

***Operating costs and expenses***

*Production expenses*

Production expenses are daily costs incurred by the Partnership to bring oil and natural gas out of the ground and to market, along with the daily costs incurred to maintain producing properties. Such costs include field personnel compensation, saltwater disposal, utilities, maintenance, repairs and servicing expenses related to the Partnership's oil and natural gas properties, along with the gathering and processing contracts in effect for the extraction, transportation and treatment of oil and natural gas.

Production expenses for the three months ended June 30, 2025 and 2024 were $3.3 million and $4.8 million, and production expenses per BOE were $19.76 and $27.34, respectively. Production expenses for the six months ended June 30, 2025 and 2024 were $7.1 million and $9.1 million, and production expenses per BOE were $22.07 and $25.25, respectively. The Partnership's production expenses during the first half of 2024 were substantially higher than the same period of 2025 due to (i) additional marketing expenses required on the sale of natural gas at low market prices, and (ii) more workover activity to ensure production from wells is maximized.

*Production taxes*

Taxes on the production and extraction of oil and natural gas are regulated and set by North Dakota tax authorities. Taxes on the sale of natural gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended June 30, 2025 and 2024 were $0.5 million (7% of revenue) and $0.9 million (10% of revenue), respectively. Production taxes for the six months ended June 30, 2025 and 2024 were $1.0 million (7% of revenue) and $1.5 million (9% of revenue), respectively. Oil production comprised approximately 51% and 55% of the Partnership's sold production volumes in the three and six months ended June 30, 2025, respectively, compared to 56% and 55% for the three and six months ended June 30, 2024.

*General and administrative expenses*

The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the three months ended June 30, 2025 and 2024 were $0.5 million in both periods. General and administrative costs for the three months ended June 30, 2025 and 2024 were $1.2 million in both periods.

*Depreciation, depletion, amortization and accretion (*"*DD&A*"*)*

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. The Partnership's DD&A for the three months ended June 30, 2025 and 2024 was $4.4 million in both periods, and DD&A per BOE of production was $26.27 and $24.93, respectively. The Partnership's DD&A for the six months ended June 30, 2025 and 2024 was $8.1 million and $8.5 million, respectively, and DD&A per BOE of production was $25.10 and $23.52, respectively. The increase in DD&A expense per BOE of production in the first half of 2025 is primarily due to the decrease of the Partnership's estimated proved reserves during the most recent reserves analyses (as of December 31, 2024 and June 30, 2025) resulting from changes in the future drill schedule and well production performance and forecasts.

***Interest expense, net***

Interest expense, net for the three months ended June 30, 2025 and 2024 was approximately $122,000 and $41,000, respectively. Interest expense, net for the six months ended June 30, 2025 and 2024 was approximately $238,000 and $36,000, respectively. The primary component of interest expense is interest expense on the Credit Facility.

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**Supplemental Non-GAAP Measure**

The Partnership uses "Adjusted EBITDAX", defined as earnings (loss) before (i) interest expense, net; (ii) income taxes; (iii) depreciation, depletion, amortization and accretion; and (iv) exploration expenses, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as an alternative to, net income, operating income, cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. Adjusted EBITDAX is not necessarily indicative of funds available to fund the Partnership's cash needs, including its ability to make cash distributions. Although Adjusted EBITDAX, as calculated by the Partnership, may not be comparable to Adjusted EBITDAX as reported by other companies that do not define such term exactly as the Partnership defines such term, the Partnership believes this supplemental measure is useful to investors when comparing the Partnership's results between periods and with other energy companies.

The Partnership believes that the presentation of Adjusted EBITDAX is important to provide investors with additional information (i) to provide an important supplemental indicator of the operational performance of the Partnership's business without regard to financing methods and capital structure, and (ii) to measure the operational performance of the Partnership's operators.

The following table reconciles the Partnership's GAAP net loss to Adjusted EBITDAX for the three and six months ended June 30, 2025 and 2024.

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| | | | | |
|:---|:---|:---|:---|:---|
|  | **Three Months<br> Ended<br> June 30,<br> 2025** | **Three Months<br> Ended<br> June 30,<br> 2024** | **Six Months<br> Ended<br> June 30,<br> 2025** | **Six Months<br> Ended<br> June 30,<br> 2024** |
| Net loss | $(2345352) | $(1427564) | $(3435946) | $(2541031) |
| Interest expense, net | 122119 | 41053 | 237733 | 36364 |
| Depreciation, depletion, amortization and accretion | 4350181 | 4350248 | 8126382 | 8464510 |
| Exploration expenses | - | - | - | - |
| &nbsp;&nbsp;&nbsp;Adjusted EBITDAX | $2126948 | $2963737 | $4928169 | $5959843 |

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**Transactions with Related Parties**

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm's length and the results of the Partnership's operations may be different than if conducted with non-related parties. The General Partner's Board of Directors oversees and reviews the Partnership's related party relationships and is required to approve any significant modifications to existing related party transactions, as well as any new significant related party transactions.

See further discussion in "Note 7. Related Parties" in Part I, Item 1 of this Form 10-Q.

**Liquidity and Capital Resources**

The Partnership's principal sources of liquidity are cash on-hand, cash flow generated from the Bakken Assets, and availability under the Partnership's Credit Facility. As of August 1, 2025, the Partnership had approximately $0.6 million in cash on-hand. The Partnership generated approximately $5.6 million and $13.4 million in cash flow from operating activities for the six months ended June 30, 2025 and the year ended December 31, 2024, respectively. The Partnership has an outstanding balance on the Credit Facility of $6.4 million at June 30, 2025, leaving $3.6 million in availability under the Credit Facility.

The Partnership anticipates that cash on-hand, cash flow from operations availability under the Credit Facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. As discussed in Note 4. Debt in Part I, Item 1 of this Form 10-Q, the Partnership was not in compliance with its debt service coverage ratio as defined within the Loan Agreement at December 31, 2024, March 31, 2025 and June 30, 2025. The Lender waived this covenant calculation for each of those quarters, and the Partnership was in compliance with its other covenants at June 30, 2025.

In August 2025, the Partnership and its Lender entered into an amendment to the Loan Agreement, that among other things, renewed and extended the Credit Facility for an additional year to March 1, 2027, and amended the definition of the debt service coverage ratio. Under the amended Loan Agreement, the debt service coverage ratio will now be a quarterly calculation starting with the quarter ended September 30, 2025, as opposed to a trailing 12-month calculation. If the Partnership is not in compliance with its covenants in future periods, the Partnership cannot provide any assurance or guarantee that covenant compliance waivers will be granted in future periods. If the Partnership is not able to obtain waivers, either (a) the Credit Facility may not be available for the Partnership's use or (b) an outstanding balance under the Credit Facility may become due on demand at that time.

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

Future growth is dependent on the Partnership's ability to add reserves in excess of production. The Partnership intends to seek opportunities to invest in its existing production wells via capital expenditures and/or drill new wells on existing leasehold sites when cash flow is available. The Partnership faces the challenge of natural production volume declines, so as reservoirs are depleted, oil and natural gas production from Partnership wells will decrease. Although the Partnership anticipates its cash on-hand, cash flow from operations and availability under the Credit Facility to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, the Partnership's cash flow from operations may decline. This could have a significant impact on the Partnership's available cash on-hand, the Partnership's ability to fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets.

***Partners***' ***Equity***

The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

Under the agreement with the Managing Dealer, the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership's best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (as defined in "Note 6. Capital Contribution and Partners' Equity" in Part 1, Item 1 of this Form 10-Q).

***Distributions***

For the three months ended June 30, 2025 and 2024, the Partnership paid distributions of $0.320541 per common unit, or $3.5 million, in both periods. For the six months ended June 30, 2025 and 2024, the Partnership paid distributions $0.641082 per common unit, or $7.1 million, in both periods.

Under the amended Loan Agreement, the Partnership is not permitted to make distributions to limited partners if paying said distribution(s) would create an event of default under the Loan Agreement. Distributions to limited partners were suspended by the General Partner in July 2025; therefore, the Partnership will accumulate all unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are to be paid before final Payout occurs, as defined above.

***Oil and Natural Gas Properties***

The Partnership incurred approximately $1.4 million and $1.7 million in capital expenditures during the six months ended June 30, 2025 and 2024, respectively. The Partnership has two wells in various stages of the drilling and completion process, and the Partnership estimates its share of capital expenditures to finish these wells is less than $1 million. In addition to the estimated capital expenditures to fully fund the in-process wells, the Partnership anticipates that it may be obligated to invest up to an additional $20 to $30 million in drilling capital expenditures from 2025 through 2029 to participate in new well development in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets.

Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for the remainder of 2025. Current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash on hand, cash generated by its producing wells and/or availability under its revolving credit facility. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to "non-consent" the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well and would be subject to a non-consent penalty.

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

***Subsequent Events***

In July 2025, the Board of Directors of the General Partner elected to suspend distributions to Partnership limited partners. The Partnership will accumulate unpaid distributions at an annualized return of seven percent (7%), and all accumulated distributions are required to be paid before final Payout occurs, as defined in the Partnership's limited partnership agreement.

The Partnership and its Lender entered into an amendment ("First Amendment") to the Loan Agreement, effective August 8, 2025 ("Effective Date"), that renewed and extended the Credit Facility for an additional year to March 1, 2027 ("Revised Maturity Date"). Key terms and conditions of the First Amendment include:

● As of the Effective Date, the borrowing base of the Credit Facility was, and remains, $10,000,000.

● The Partnership paid a loan renewal fee to the Lender associated with the First Amendment of $50,000.

● The Debt Service Coverage Ratio has been amended to be a quarter-based calculation, as opposed to a trailing 12-month calculation that was previously in effect, and will be effective starting with the quarter ended September 30, 2025.

● A negative covenant has been added that restricts the Partnership's ability to make future distributions to its limited partners if that said distribution would create an event of default under the Loan Agreement.

All other terms and conditions of the BF Loan Agreement and its subsequent amendments remain in effect.

**Item 3. Quantitative and Qualitative Disclosures About Market Risk**

Not applicable.

**Item 4. Controls and Procedures**

***Evaluation of Disclosure Controls and Procedures***

In accordance with Exchange Act Rule 13a–15 and 15d–15 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, of the effectiveness of the Partnership's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of June 30, 2025 to provide reasonable assurance that information required to be disclosed in the Partnership's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Partnership's disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

***Change in Internal Controls Over Financial Reporting***

There have not been any changes in the Partnership's internal controls over financial reporting that occurred during the quarterly period ended June 30, 2025 that have materially affected, or are reasonably likely to materially affect, the Partnership's internal controls over financial reporting.

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

**PART II. OTHER INFORMATION**

**Item 1. Legal Proceedings.**

At the end of the period covered by this Quarterly Report on Form 10-Q, the Partnership was not a party to any material, pending legal proceedings.

**Item 1A. Risk Factors**

For a discussion of the Partnership's potential risks and uncertainties, see the section titled "Risk Factors" in the Partnership's 2024 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2024 Form 10-K.

**Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.**

Not applicable.

**Item 3. Defaults upon Senior Securities.**

Not applicable.

**Item 4. Mine Safety Disclosures.**

Not applicable.

**Item 5. Other Information.**

Not applicable.

**Item 6. Exhibits.**

---

| | |
|:---|:---|
| **Exhibit No.** | **Description** |
| 10.1 | [First Amendment to Credit Agreement dated effective as of August 9, 2025 by and among Energy Resources 12 Operating Company, LLC and Energy Resources 12, L.P., as Borrowers, and BancFirst, as Lender hereto\*](er12lpex10-1.htm) |
| 31.1 | [Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002\*](er12lpex31-1.htm) |
| 31.2 | [Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002\*](er12lpex31-2.htm) |
| 32.1 | [Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002\*](er12lpex32-1.htm) |
| 32.2 | [Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002\*](er12lpex32-2.htm) |
| 101 | The following materials from Energy Resources 12, L.P.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2025 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners' Equity, (iv) the Consolidated Statements of Cash Flows, and (v) related notes to the consolidated financial statements, tagged as blocks of text and in detail\* |
| 104 | The cover page from the Partnership's Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, formatted in iXBRL and contained in Exhibit 101. |

---

\* Filed herewith.

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**SIGNATURES**

Pursuant to the requirements of Section 13 or 15(d) 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.

---

| | |
|:---|:---|
| **Energy Resources 12, L.P.** | **Energy Resources 12, L.P.** |
| By: | Energy Resources 12 G.P., LLC, its General Partner |
| By: | /s/ Glade M. Knight |
|  | Glade M. Knight |
|  | Chief Executive Officer<br> (Principal Executive Officer) |
| By: | /s/ David S. McKenney |
|  | David S. McKenney |
|  | Chief Financial Officer <br> (Principal Financial and Accounting Officer) |

---

Date: August 13, 2025

## Exhibit 10.1

**EXHIBIT 10.1**

**LOAN MODIFICATION AGREEMENT**

This Loan Modification Agreement ("Modification") is made and entered into effective the 8<sup>th</sup> day of August, 2025 by and among **ENERGY RESOURCES 12 OPERATING COMPANY, LLC**, a Delaware limited liability company ("**<u>Energy 12 Operating</u>**") and **ENERGY RESOURCES 12, L.P**., a Delaware limited partnership ("**<u>Energy 12 LP</u>**"; Energy 12 Operating and Energy 12 LP are jointly, severally and collectively referred to herein as the "**<u>Borrowers</u>**" and each individually as a "**<u>Borrower</u>**"), **ENERGY RESOURCES 12 GP**, LLC, a Delaware limited liability company ("the "**<u>Guarantor</u>**"), and **BANCFIRST,** an Oklahoma banking corporation ("**<u>Lender</u>**")

RECITALS

WHEREAS, on May 2, 2024, Borrowers and Lender entered into that certain Credit Agreement (the "Existing Agreement"), whereby Lender provided Borrowers with a revolving commitment up to the maximum amount of $20,000,000.00, as evidenced by promissory note with a stated like amount dated effective as of May 2, 2024 ("Existing Note"); and

WHEREAS, the obligations described in the Existing Agreement are secured by, among other things not specifically set forth herein, the Collateral as set forth in the Existing Agreement and the Loan Documents;

WHEREAS, the obligations described in the Existing Agreement are guaranteed by Guarantor as referenced in the Guaranty;

WHEREAS, the parties now desire to amend the Existing Agreement and Existing Note in order to, among other things, extend the maturity date; and

WHEREAS, all capitalized terms not otherwise defined herein shall have those meanings assigned to such terms in the Existing Agreement;

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties agree as follows:

A. MODIFICATION TO EXISTING AGREEMENT.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. The definitions of the terms "Debt Service Coverage Ratio", "EBITDAX" and "Maturity Date" set forth at Section 1.01 of the Existing Agreement are hereby amended and restated in their entirety as follows:

"**<u>Debt Service Coverage Ratio</u>**" means that ratio determined by dividing EBITDAX less distributions by the sum of the Consolidated Borrower Entities' interest expense plus the quarterly amount of the principal payment necessary to amortize the loan balance over the Half Life of Borrowers' Oil and Gas Properties plus any additional current maturities of long term debt due from other Debt for the most recent calendar quarter then-ended.

"**<u>EBITDAX</u>**" means, with respect to the Consolidated Borrower Entities for the most recent calendar quarter then ended: (a) Net Income of the Consolidated Borrower Entities for such period, plus, to the extent deducted in the calculation of Net Income, (b) the sum of (i) income or franchise Taxes paid or accrued; (ii) interest expense; (iii) amortization, depletion and depreciation expense; (iv) exploration expenses; (v) IDCs; (vi) any loss from the sale of assets; (vii) impairments; (viii) any non-cash losses or charges on any Swap Agreement resulting from the requirements of SFAS 133 for that period; (ix) non-recurring expenses or losses (including, any extraordinary expenses or losses); (x) any other non-cash expenses or non-cash losses; <u>less</u>, to the extent included in the calculation of Net Income, (c) the sum of (i) gains or losses from sales or other dispositions of assets (other than Hydrocarbons produced in the normal course of business); (ii) any non-cash gains on any Swap Agreement resulting from the requirements of SFAS 133 for that period; and (iii) extraordinary or non-recurring gains, but not net of extraordinary or non-recurring "cash" losses.

"**<u>Maturity Date</u>**" means the earliest of (a) March 1, 2027 and (b) the date on which the Commitment is reduced to zero or otherwise terminated pursuant to the terms hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2. The following definition for the term "Restricted Payment" shall be added to the Existing Agreement in its appropriate alphabetical order:

"**<u>Restricted Payment</u>**" means any dividend or other distribution (whether in cash, securities or other Property) with respect to any Equity Interests in any Borrower, or any payment (whether in cash, securities or other Property), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such Equity Interests in any Borrower or any option, warrant or other right to acquire any such Equity Interests in any Borrower.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3. The caption of Section 9.19 of the Existing Agreement is hereby deleted and replaced with "Non-Qualified ECP Guarantor".

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4. An additional negative covenant shall be added to Article IX of the Existing Agreement as Section 9.20 which shall be captioned "Dividends and Distributions" and which shall state as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;9.20 **<u>Restricted Payments</u>**. No Borrower will, nor will it permit any Subsidiary to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, return any capital to its stockholders or make any distribution of its Property to its Equity Interest holders following the occurrence of an Event of Default or if making such a Restricted Payment would cause or create an Event of Default. Borrower recognizes and agrees that its ability to make a Restricted Payment following the occurrence of an Event of Default will be suspended until such Event of Default is cured in accordance herewith and/or waived by Lender.

B. MODIFICATION OF LOAN DOCUMENTS. The terms of any other Loan Document executed in connection with the Existing Agreement, or any amendment thereof, are hereby modified to reflect the modifications referenced in Section A above. Except as modified by the paragraphs above, the Existing Note and other Loan Documents continue in full force and effect and are hereby ratified and confirmed by Borrower. Hereafter, references to the Note and Loan Documents in the Loan Documents shall be deemed to be references to the Note and Loan Documents as amended and modified by this Modification. ***<u>Further, this Modification constitutes an amendment of and not a replacement or payment of the Note.</u>***

C. WAIVER.

Notwithstanding the foregoing, subject to the terms and conditions set forth herein, Lender hereby waives the violation of the Existing Agreement occurring as a result of the Borrower's failure to comply with the "Financial Covenant" set forth at Section 9.01(b) of the Existing Agreement for the reporting period ending June 30, 2025 (the "Violation"). But for this waiver, the Violation would and/or will constitute an Event of Default under the Existing Agreement. The aforementioned waiver is on a one-time basis. Lender is in no way setting any type of future precedent pertaining to future failures to comply with the covenants set forth above or any other provision of the Existing Agreement. This waiver shall not extend to any other Event of Default set forth in the Existing Agreement, and such waiver is granted without prejudice to, and does not constitute a waiver or release of, the Lender's right at any time in the future to exercise any and all rights and remedies conferred upon the Lender by the Existing Agreement or otherwise at law or in equity, with regard to future defaults including, but not limited to, any Event of Default occasioned by future failures under Section 9.01(b) of the Existing Agreement.

D. CONDITIONS PRECEDENT TO LENDER'S COMMITMENT TO AMEND AND WAIVE. This Amendment shall become effective as of the date first above written when and only when:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. <u>Amendment Documents</u>. Lender shall have received duly executed and delivered counterparts of this modification and any modifications or amendments to any other Loan Document deemed reasonably necessary by Lender (collectively, the "Amendment Documents") in form, substance and date reasonably satisfactory to Lender, and in such numbers as Lenders or its counsel may reasonably request.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2. <u>Collateral Matters</u>. Lender and/or Borrowers, as applicable shall have executed and delivered new Security Instruments or an amendment to any Mortgages deemed reasonably necessary by Lender.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3. <u>Due Diligence</u>. Lender shall have completed satisfactory due diligence review of the assets, liabilities, business, operations and condition (financial or otherwise) of Borrowers.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4. <u>Other Documentation</u>. Lender shall have received all documents and instruments which Lender has then reasonably requested, in addition to those described in this Section 6. All such additional documents and instruments shall be reasonably satisfactory to Lender in form, substance and date.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5. <u>No Default</u>. No event shall have occurred and be continuing that would constitute an Event of Default or a Default.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6. <u>Fee</u>. Lender shall have received a non-refundable $50,000.00 fee.

E. MISCELLANEOUS REPRESENTATIONS AND COVENANTS

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. Borrower acknowledges that the Existing Note is a valid and legally binding obligation of Borrower, enforceable in accordance with its terms, and is not subject to any defenses, counterclaims or offsets of any kind.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2. Borrower acknowledges that any and all security agreements, mortgages, guaranties and similar instruments securing payment of the Existing Note and indebtedness evidenced thereby shall continue in full force and effect as security for the Existing Note until the Existing Note is paid and satisfied in full.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3. Borrower covenants and agrees to execute and deliver any and all mortgages, deeds of trust, security agreements and/or amendments to any such documents currently in place necessary, in the reasonable discretion of Lender as may be required from time to time, to attach, place and/or perfect a lien in favor of Lender against any properties securing the indebtedness evidenced by the Existing Agreement and the Existing Note.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4. Effective as of the date hereof, Borrower shall have paid all accrued but unpaid interest due and owing on the Existing Note. Borrower shall continue making payments of interest as set forth in the Existing Note, as modified hereby.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5. Except as modified by this Modification, the Existing Note, Existing Agreement and all other Loan Documents (as such terms are defined in the Existing Agreement) shall remain in full force and effect in accordance with the original terms of such Existing Note, Existing Agreement, and Loan Documents.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6. The failure of Borrower to comply with any material provision of this Modification or the breach of any material representation, warranty or covenant contained in this Modification shall constitute an Event of Default under the Note, the Agreement, and all other Loan Documents, and any such Event of Default shall entitle Lender to exercise any and all remedies to which it may be entitled with respect to an Event of Default under such documents.

F. BORROWING BASE AND OTHER NOTIFICATIONS. From the date hereof through the next redetermination of the Borrowing Base as set forth in the Existing Agreement on March 1, 2026 (or earlier pursuant to an Interim Redetermination), the Borrowing Base shall be $10,000,000.00, the Half Life shall be 60 months and the Monthly Commitment Reductions shall be $0.00. Borrowers acknowledge that this Amendment satisfies all notification requirements set forth in the Agreement pertaining to the Borrowing Base. Further, Borrower continues to understand and agree that its ability to obtain additional advances pursuant to the Existing Agreement and Existing Note, as modified hereby, is terminated

***The remainder of this page has been left intentionally blank.***

IN WITNESS WHEREOF, the parties hereto have caused this Modification to be executed on the day and year first above written.

---

| | | |
|:---|:---|:---|
| **<u>BORROWERS</u>**: | **ENERGY RESOURCES 12 OPERATING COMPANY, LLC,** a Delaware limited liability company | **ENERGY RESOURCES 12 OPERATING COMPANY, LLC,** a Delaware limited liability company |
|  | By: | ENERGY RESOURCES 12, L.P., a Delaware limited partnership |
|  | Title: | Sole Member |
|  | By: | Energy Resources 12 GP, LLC, a Delaware limited liability company |
|  | Title: | General Partner |
|  | By: | /s/ David McKenney |
|  |  | David McKenney, Manager/Chief Financial Officer |
|  | **ENERGY RESOURCES 12, L.P.** | **ENERGY RESOURCES 12, L.P.** |
|  | By: | Energy Resources 12 GP, LLC, a Delaware limited liability company |
|  | Title: | General Partner |
|  | By: | /s/ David McKenney |
|  |  | David McKenney, Manager/Chief Financial Officer |
| **<u>GUARANTOR</u>**: | **ENERGY RESOURCES 12 GP, LLC,** a Delaware limited liability company | **ENERGY RESOURCES 12 GP, LLC,** a Delaware limited liability company |
|  | By: | /s/ David McKenney |
|  |  | David McKenney, Manager/Chief Financial Officer |
| **<u>LENDER</u>**: | **BANCFIRST**, an Oklahoma banking corporation | **BANCFIRST**, an Oklahoma banking corporation |
|  | By: | /s/ Heather Healey Whiteside |
|  |  | Heather Healey Whiteside, Senior Vice President |

---

## Exhibit 31.1

**EXHIBIT 31.1**

**CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)**

I, Glade M. Knight, certify that:

1. I
have reviewed this Quarterly Report on Form 10-Q of Energy Resources 12, L.P. (the "registrant");

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 officer 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;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;

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;

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

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 officer 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 functions):

&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

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.

---

| | | |
|:---|:---|:---|
| Date: August 13, 2025 | By: | /s/ Glade M. Knight |
|  | Name: | Glade M. Knight |
|  | Title: | General Partner, Chief Executive Officer |
|  |  | (Principal Executive Officer) |

---

## Exhibit 31.2

**EXHIBIT 31.2**

**CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)**

I, David S. McKenney, certify that:

1. I
have reviewed this Quarterly Report on Form 10-Q of Energy Resources 12, L.P. (the "registrant");

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 officer 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;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;

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;

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

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 officer 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 functions):

&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

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.

---

| | | |
|:---|:---|:---|
| Date: August 13, 2025 | By: | /s/ David S. McKenney |
|  | Name: | David S. McKenney |
|  | Title: | General Partner, Chief Financial Officer |
|  |  | (Principal Financial and Accounting Officer) |

---

## Exhibit 32.1

**EXHIBIT 32.1**

**CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002**

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Quarterly Report on Form 10-Q (the "Form 10-Q") for the three months ended June 30, 2025 of Energy Resources 12, L.P. (the "Partnership"). I, Glade M. Knight, the Chief Executive Officer of the Partnership, certify that, based on my knowledge:

&nbsp;&nbsp;&nbsp;&nbsp;(1) The
Form 10-Q fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;(2) The
information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of
the Partnership as of and for the periods covered in this report.

---

| | | |
|:---|:---|:---|
| Date: August 13, 2025 | By: | /s/ Glade M. Knight |
|  | Name: | Glade M. Knight |
|  | Title: | General Partner, Chief Executive Officer |
|  |  | (Principal Executive Officer) |

---

## Exhibit 32.2

**EXHIBIT 32.2**

**CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002**

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Quarterly Report on Form 10-Q (the "Form 10-Q") for the three months ended June 30, 2025 of Energy Resources 12, L.P. (the "Partnership"). I, David S. McKenney, the Chief Financial Officer of the Partnership, certify that, based on my knowledge:

&nbsp;&nbsp;&nbsp;&nbsp;(1) The
Form 10-Q fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;(2) The
information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of
the Partnership as of and for the periods covered in this report.

---

| | | |
|:---|:---|:---|
| Date: August 13, 2025 | By: | /s/ David S. McKenney |
|  | Name: | David S. McKenney |
|  | Title: | General Partner, Chief Financial Officer |
|  |  | (Principal Financial and Accounting Officer) |

---