# Epsilon Energy Ltd.: Form 10-Q for the period ended Sep 30, 2025

- Company: [Epsilon Energy Ltd.](/companies/epsn.md) (CIK 1726126)
- Form: 10-Q
- Filed: 2025-11-05
- Accepted by EDGAR: Nov 5, 2025, 16:07 ET
- Period: 2025-09-30
- Accession: 0001104659-25-106988
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1726126/000110465925106988/epsn-20250930x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1726126/000110465925106988/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-07-01 to 2025-09-30 | $9.0m | us-gaap:RevenueFromContractWithCustomerIncludingAssessedTax |
| Revenue | 9 months, 2025-01-01 to 2025-09-30 | $36.8m | us-gaap:RevenueFromContractWithCustomerIncludingAssessedTax |
| Operating income | 3 months, 2025-07-01 to 2025-09-30 | $606.0k | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2025-01-01 to 2025-09-30 | $8.6m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-07-01 to 2025-09-30 | $11.7k | us-gaap:InterestExpenseNonoperating |
| Interest expense | 9 months, 2025-01-01 to 2025-09-30 | $43.8k | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2025-07-01 to 2025-09-30 | $576.5k | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2025-01-01 to 2025-09-30 | $4.1m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-07-01 to 2025-09-30 | $1.1m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2025-01-01 to 2025-09-30 | $6.6m | us-gaap:ProfitLoss |
| Diluted EPS | 3 months, 2025-07-01 to 2025-09-30 | $0.05 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2025-01-01 to 2025-09-30 | $0.30 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-07-01 to 2025-09-30 | $0.05 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2025-01-01 to 2025-09-30 | $0.30 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-07-01 to 2025-09-30 | 22,159,532 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2025-01-01 to 2025-09-30 | 22,170,223 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2025-01-01 to 2025-09-30 | $20.9m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 9 months, 2025-01-01 to 2025-09-30 | $0 | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2025-09-30 | $12.8m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-09-30 | $19.1m | us-gaap:AssetsCurrent |
| Total assets | at 2025-09-30 | $126.3m | us-gaap:Assets |
| Current liabilities | at 2025-09-30 | $9.9m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-09-30 | $26.1m | us-gaap:Liabilities |
| Shareholders' equity | at 2025-09-30 | $100.2m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 35,940 characters.

*The following discussion is intended to assist in the understanding of trends and significant changes in our results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented. The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report, including the unaudited condensed consolidated financial statements as of September 30, 2025 and 2024 together with accompanying notes, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward- looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Forward-Looking Statements.”*

### Overview

Epsilon Energy Ltd. (the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our primary areas of operations are the Marcellus shale section of the Appalachian basin in Pennsylvania, the Permian Basin in Texas and New Mexico, the NW Anadarko Basin in Oklahoma, and the Western Canadian Sedimentary Basin in Alberta, Canada.

At September 30, 2025 we held leasehold rights to 21,490 net acres. We have natural gas production from our non-operated wells in Pennsylvania, and oil, natural gas liquids, and natural gas production from our non-operated wells in Texas, New Mexico, Oklahoma, and Alberta, Canada.

At December 31, 2024 our total estimated net proved reserves were 69,401 MMcf of natural gas, 876,808 Bbls of NGLs, and 1,572,465 Bbls of oil and condensate.

In Pennsylvania, the Company owns a 35% interest in the 45-mile Auburn Gas Gathering System (“Auburn GGS") which is operated by a subsidiary of Williams Partners, LP.

Our common shares trade on the NASDAQ Global Market under the ticker symbol “EPSN.”

### Business Strategy

We are committed to disciplined capital allocation including shareholder returns in the form of dividends and share buybacks. We plan to maintain a strong balance sheet and liquidity position to allow us to opportunistically invest in both our existing project areas and potential new projects.

Historically, our investments have been focused on our position in the Marcellus unconventional reservoir in Pennsylvania (“PA”). Our PA assets are supported by our 35% ownership in the Auburn GGS and we have a substantial remaining drillable location inventory within our existing leaseholds.

More recently, our investments have been focused in the Permian Basin in Texas and the Western Canadian Sedimentary Basin in Alberta, Canada.

On February 26, 2024, Epsilon acquired a 25% interest in three producing wells and 3,620 gross undeveloped acres in Ector County, Texas from a private operator. The Company participated in the drilling and completion of 2 gross (0.5 net) wells during 2024 which were put on production in May 2024 and July 2024. Together with the transaction completed in 2023, the Company holds a 25% working interest in 16,446 gross acres and 8 producing wells in Texas. Total capital expenditures (net to Epsilon) through September 30, 2025 in the project (including undeveloped leasehold) are $42 million.

On April 11, 2024, Epsilon acquired a 50% working interest in 14,243 gross undeveloped acres in Alberta, Canada. The Company participated in the drilling and completion of 2 gross (0.5 net) wells. One well was put on production in September 2024. One well was deemed non-commercial. Total capital expenditures (net to Epsilon) through September 30, 2025 in the project (including undeveloped leasehold) are $3.5 million (pre-impairment).

In October 2024, Epsilon formed a joint venture with a private operator covering approximately 130,000 gross acres in Garrington and Harmattan areas in Alberta, Canada. The Company provided a $7 million drilling carry in favor of the operator in exchange for a 25% working interest in the leasehold. To date, the Company participated in the drilling and completion of 2 gross (0.5 net) wells. Total capital expenditures (net to Epsilon) through September 30, 2025 are $9.0 million (prior to $2.7 million of impairment during the nine months ended September 30, 2025).

On August 11, 2025, Epsilon signed definitive agreements to acquire two entities (Peak Exploration and Production LLC and Peak BLM Lease LLC, together “**Peak”**) majority owned by funds of Yorktown Energy Partners LLC. Combined consideration due at closing is the issuance of 6 million Epsilon common shares and the assumption of an estimated $51.2 million of debt. Additional contingent consideration of up to 2.5 million Epsilon common shares could be due subject to the ability to access acreage currently affected by a drilling permit moratorium in Converse County, Wyoming. The assets to be acquired include an operated position of 40,500 net acres producing 2.2 MBoepd in the Powder River Basin in Campbell and Converse County, Wyoming. The transactions are expected to close in Q4 2025, subject to obtaining the requisite Epsilon shareholder approval.

### Three and nine months ended September 30, 2025 Highlights

### Operational Highlights

#### Marcellus Shale – Pennsylvania

- During the three months ended September 30, 2025, Epsilon's realized natural gas price was $2.24 per Mcf, a 46% increase over the three months ended September 30, 2024. During the nine months ended September 30, 2025, Epsilon's realized natural gas price was $2.95 per Mcf, an 85% increase over the nine months ended September 30, 2024.
- During the three months ended September 30, 2025, Epsilon’s net revenue interest natural gas production was 2.0 Bcf, a 67% increase over the three months ended September 30, 2024. During the nine months ended September 30, 2025, Epsilon’s net revenue interest natural gas production was 7.0 Bcf, an 75% increase over the nine months ended September 30, 2024.
- Gathered and delivered 8.9 Bcf gross (3.1 net to Epsilon's interest) during the three months ended September 30, 2025, or 96 MMcf/d through the Auburn Gas Gathering System. Gathered and delivered 31.8 Bcf gross (11.1 net to Epsilon's interest) during the nine months ended Sept 30, 2025, or 116 MMcf/d through the Auburn Gas Gathering System.

#### Permian Basin – Texas and New Mexico

- During the three months ended September 30, 2025, Epsilon's realized price for all Permian Basin production was $50.19 per Boe (90% liquids), a 7% decrease over the three months ended September 30, 2024. During the nine months ended September 30, 2025, Epsilon's realized price for all Permian Basin production was $52.43 per Boe (88% liquids), a 2.6% decrease over the nine months ended September 30, 2024.
- Total net revenue interest production for the three months ended September 30, 2025, which included oil, natural gas liquids, and natural gas, was 47.8 Mboe compared to 73.3 Mboe during the same period in 2024, a 35% decrease. Total net revenue interest production for the nine months ended September 30, 2025, which included oil, natural gas liquids, and natural gas, was 152.7 Mboe compared to 191.4 Mboe during the same period in 2024, a 20% decrease.
- During the nine months ended September 30, 2025, the Company had 1 gross (.25 net) well drilled and completed. The well turned online in July 2025.

#### Anadarko, NW Stack Trend – Oklahoma

- During the three months ended September 30, 2025, Epsilon's realized price for all Oklahoma production was $3.84 per Mcfe (57% natural gas), a 7% decrease from the three months ended September 30, 2024. During the nine months ended September 30, 2025, Epsilon's realized price for all Oklahoma production was $4.55 per Mcfe (60% natural gas), a 6% increase from the nine months ended September 30, 2024.
- Total net revenue interest production for the three months ended September 30, 2025 included natural gas, oil and other liquids and was 0.07 Bcfe, a 23% decrease from the same period in 2024. Total net revenue interest production for the nine months ended September 30, 2025 included natural gas, oil and other liquids and was 0.2 Bcfe, a 22% decrease from the same period in 2024.

#### Western Canadian Sedimentary Basin—Alberta, Canada

- During the three months ended September 30, 2025, Epsilon's realized price for all Canada production was $31.54 per Boe (63% liquids). During the nine months ended September 30, 2025, Epsilon's realized price for all Canada production was $38.89 per Boe (73% liquids). The Company had no Canada production in 2024.
- Total net revenue interest production for the three months ended September 30, 2025, which included oil, natural gas liquids, and natural gas, was 8.2 Mboe. Total net revenue interest production for the nine months ended September 30, 2025, which included oil, natural gas liquids, and natural gas, was 21.2 Mboe.

### Non-GAAP Financial Measures-Adjusted EBITDA

Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) gain or loss on sale of assets, (7) gain or loss on derivative contracts net of cash received or paid on settlement, and (8) net other income (expense). Adjusted EBITDA is not a measure of financial performance as determined under U.S. GAAP and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with U.S. GAAP or as a measure of profitability or liquidity.

Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Epsilon has included Adjusted EBITDA as a supplemental disclosure because its management believes that Adjusted EBITDA provides useful information regarding its ability to service debt and to fund capital expenditures. It further provides investors a helpful measure for comparing operating performance on a normalized or recurring basis with the performance of other companies, without giving effect to certain non-cash expenses and other items. This provides management, investors and analysts with comparative information for evaluating the Company in relation to other natural gas and oil companies providing corresponding non-U.S. GAAP financial measures or that have different financing and capital structures or tax rates. These non-U.S. GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with U.S. GAAP.

The table below sets forth a reconciliation of net income to Adjusted EBITDA for the three and nine months ended September 30, 2025 and 2024, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully.

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| **Net income** | **​** | $1,072,295 | ​ | $366,021 | ​ | $6,639,790 | ​ | $2,688,577 |
| Add Back: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Interest income, net | ​ | ​ (73,228) | ​ | ​ (43,095) | ​ | ​ (73,657) | ​ | ​ (400,791) |
| Income tax expense | ​ | ​ 576,497 | ​ | ​ 368,398 | ​ | ​ 4,084,378 | ​ | ​ 881,464 |
| Depreciation, depletion, amortization, and accretion | **​** | **​** 2,570,462 | ​ | ​ 2,698,812 | **​** | **​** 9,247,973 | ​ | ​ 7,127,641 |
| Impairment expense | **​** | **​** — | ​ | ​ — | **​** | **​** 2,676,669 | ​ | ​ — |
| Stock based compensation expense | ​ | ​ 376,613 | ​ | ​ 309,109 | ​ | ​ 1,148,289 | ​ | ​ 944,267 |
| (Gain) loss on derivative contracts net of cash received or paid on settlement | ​ | ​ (156,659) | ​ | ​ 44,677 | ​ | ​ (1,376,735) | ​ | ​ 1,000,836 |
| Foreign currency translation loss | ​ | ​ (710) | ​ | ​ — | ​ | ​ 23,601 | ​ | ​ 570 |
| **Adjusted EBITDA** | **​** | **$4,365,270** | **​** | **$3,743,922** | **​** | **$22,370,308** | **​** | **$12,242,564** |

### Results of Operations

### Net Operating Revenues

For the nine months ended September 30, 2025 revenues increased $14.2 million, or 63%, to $36.8 million from $22.6 million during the same period of 2024.

Revenue and volume statistics for the three and nine months ended September 30, 2025 and 2024 were as follows:

| ​ ​ ​ ​ Revenues Pennsylvania | ​ ​ ​ ​ ​ | ​ ​ Three months ended September 30, 2025 ​ ​ ​ ​ | ​ ​ ​ | ​ ​ 2024 ​ ​ ​ ​ | ​ ​ ​ ​ ​ | ​ ​ Nine months ended September 30, 2025 ​ ​ ​ ​ | ​ ​ ​ | ​ ​ 2024 ​ ​ ​ ​ |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Natural gas revenue | ​ | $4,591,423 | ​ | $1,833,371 | ​ | $21,621,448 | ​ | $6,435,027 |
| Volume (MMcf) | ​ | 2,045 | ​ | 1,190 | ​ | 7,336 | ​ | 4,032 |
| Avg. Price ($/Mcf) | ​ | $2.24 | ​ | $1.54 | ​ | $2.95 | ​ | $1.60 |
| Gathering system revenue (net of elimination) | ​ | $1,445,211 | ​ | $1,083,988 | ​ | $5,182,566 | ​ | $4,464,134 |
| **Total PA Revenues** | **​** | **$6,036,634** | **​** | **$2,917,359** | **​** | **$26,804,014** | **​** | **$10,899,161** |
| Permian Basin | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Natural gas revenue | ​ | $39,312 | ​ | $(27,499) | ​ | $134,840 | ​ | $11,322 |
| Volume (MMcf) | ​ | 28 | ​ | 57 | ​ | 108 | ​ | 158 |
| Avg. Price ($/Mcf) | ​ | $1.42 | ​ | $(0.48) | ​ | $1.25 | ​ | $0.07 |
| Natural gas liquids revenue | ​ | $167,132 | ​ | $239,262 | ​ | $493,930 | ​ | $780,946 |
| Volume (MBOE) | ​ | 9.2 | ​ | 13.1 | ​ | 24.5 | ​ | 39.1 |
| Avg. Price ($/Bbl) | ​ | $18.21 | ​ | $18.31 | ​ | $20.18 | ​ | $19.99 |
| Oil and condensate revenue | ​ | $2,193,192 | ​ | $3,757,574 | ​ | $7,376,168 | ​ | $9,510,780 |
| Volume (MBbl) | ​ | 34.0 | ​ | 50.7 | ​ | 110.2 | ​ | 126.1 |
| Avg. Price ($/Bbl) | ​ | $64.45 | ​ | $74.11 | ​ | $66.94 | ​ | $75.45 |
| **Total Permian Basin Revenues** | **​** | **$2,399,636** | **​** | **$3,969,337** | **​** | **$8,004,938** | **​** | **$10,303,048** |
| Oklahoma | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Natural gas revenue | ​ | $117,000 | ​ | $98,074 | ​ | $490,975 | ​ | $381,806 |
| Volume (MMcf) | ​ | 45 | ​ | 57 | ​ | 150 | ​ | 188 |
| Avg. Price ($/Mcf) | ​ | $2.61 | ​ | $1.72 | ​ | $3.28 | ​ | $2.04 |
| Natural gas liquids revenue | ​ | $70,337 | ​ | $96,009 | ​ | $252,415 | ​ | $315,732 |
| Volume (MBOE) | ​ | 3.4 | ​ | 4.1 | ​ | 10.8 | ​ | 13.4 |
| Avg. Price ($/Bbl) | ​ | $20.49 | ​ | $23.60 | ​ | $23.33 | ​ | $23.55 |
| Oil and condensate revenue | ​ | $100,271 | ​ | $207,162 | ​ | $391,654 | ​ | $682,755 |
| Volume (MBbl) | ​ | 1.6 | ​ | 2.7 | ​ | 5.8 | ​ | 8.7 |
| Avg. Price ($/Bbl) | ​ | $64.61 | ​ | $77.33 | ​ | $67.31 | ​ | $78.06 |
| **Total OK Revenues** | **​** | **$287,608** | **​** | **$401,245** | **​** | **$1,135,044** | **​** | **$1,380,293** |
| Canada | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Natural gas revenue | ​ | $10,843 | ​ | $— | ​ | $35,232 | ​ | $— |
| Volume (MMcf) | ​ | 18 | ​ | — | ​ | 35 | ​ | — |
| Avg. Price ($/Mcf) | ​ | $0.60 | ​ | $— | ​ | $1.01 | ​ | $— |
| Natural gas liquids revenue | ​ | $29,550 | ​ | $— | ​ | $52,944 | ​ | $— |
| Volume (MBOE) | ​ | 1.4 | ​ | — | ​ | 2.3 | ​ | — |
| Avg. Price ($/Bbl) | ​ | $21.76 | ​ | $— | ​ | $23.05 | ​ | $— |
| Oil and condensate revenue | ​ | $217,188 | ​ | $— | ​ | $737,160 | ​ | $— |
| Volume (MBbl) | ​ | 3.8 | ​ | — | ​ | 13.1 | ​ | — |
| Avg. Price ($/Bbl) | ​ | $56.89 | ​ | $— | ​ | $56.24 | ​ | $— |
| **Total Canada Revenues** | **​** | **$257,581** | **​** | **$—** | **​** | **$825,336** | **​** | **$—** |
| **Total Revenues** | **​** | **$8,981,459** | **​** | **$7,287,941** | **​** | **$36,769,332** | **​** | **$22,582,502** |

Upstream natural gas revenue for the nine months ended September 30, 2025 increased by $15.5 million, or 226%, over the same period in 2024. An increase of $10.4 million was due to higher natural gas prices and an increase of $5.1 million was a result of previously delayed turn in line wells coming online in Pennsylvania and the end of operator- elected well shut-ins in Pennsylvania. Upstream natural gas revenue for the three months ended September 30, 2025 increased by $2.8 million, or 150%, over the same period in 2024. An increase of $1.6 million was due to higher natural gas prices and an increase of $1.2 million was a result of previously delayed turn in line wells coming online in Pennsylvania and the end of operator-elected well shut-ins in Pennsylvania.

Upstream natural gas liquids revenue for the nine months ended September 30, 2025 decreased by $0.3 million, or 27%, over the same period in 2024. This decrease was mostly due to lower volumes in the Permian Basin as a result of processing disruptions at the Goldsmith plant in Texas as well as gas flaring due to negative residue gas pricing in the second and third quarter. Upstream natural gas liquids revenue for the three months ended September 30, 2025 decreased by $0.07 million, or 20%, over the same period in 2024. This decrease was mostly due to lower volumes in the Permian Basin as a result of the aforementioned processing disruptions and negative residue gas pricing.

Upstream oil and condensate revenue for the nine months ended September 30, 2025 decreased by $1.7 million, or 17% over the same period in 2024. A decrease of $1.3 million was due to lower oil prices and a decrease of $0.4 million was due to lower volumes from well shut-ins for adjacent completion operations and natural decline. Upstream oil and condensate revenue for the three months ended September 30, 2025 decreased by $1.5 million, or 37% over the same period in 2024. A decrease of $1 million was due to lower volumes from the aforementioned well shut-ins and natural decline and a decrease of $0.4 million was due to lower prices.

Gathering system revenue for the nine months ended September 30, 2025 increased by $0.7 million, or 16%, compared with the same period in 2024 as a result of slightly higher throughput, but more importantly, crossflow gas being displaced with Anchor Shipper gas which is charged a higher gathering fee. Gathering system revenue for the three months ended September 30, 2025 increased by $0.4 million, or 33%, compared with the same period in 2024 due to higher volumes and a higher percentage of Anchor Shipper gas. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $0.4 million and $1.5 million, respectively, for the three and nine months ended September 30, 2025, and $0.3 million and $0.8 million, respectively, for the three and nine months ended September 30, 2024.

### Operating Costs

The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the three and nine months ended September 30, 2025 and 2024:

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Lease operating costs (net of elimination) | ​ | $2,397,052 | ​ | $2,099,501 | ​ | $7,615,735 | ​ | $5,517,830 |
| Gathering system operating costs | ​ | ​ 563,542 | ​ | ​ 490,325 | ​ | ​ 1,729,988 | ​ | ​ 1,692,862 |
| **​** | **​** | **$2,960,594** | **​** | **$2,589,826** | **​** | **$9,345,723** | **​** | **$7,210,692** |
| ​ | ​ | ​ **​** | **​** | **​** **​** | ​ | ​ **​** | **​** | **​** **​** |
| Upstream operating costs—Total $/Mcfe | ​ | $0.98 | ​ | $1.22 | ​ | $0.88 | ​ | $1.00 |
| Gathering system operating costs $/Mcf | ​ | $0.18 | ​ | $0.19 | ​ | $0.15 | ​ | $0.16 |

Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system.

Upstream operating costs consist of lease operating expenses necessary to extract natural gas and oil, including gathering and treating the natural gas and oil in preparation for sale. For the nine months ended September 30, 2025 these costs increased by $2.1 million, or 38%, over the same period in 2024. The increase is primarily due to higher volumes. For the three months ended September 30, 2025 these costs increased by $0.3 million, or 14%, over the same period in 2024. The increase is due to non-recurring plugging and abandonment expenses above previously estimated asset retirement obligations.

Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units and overhead fees due to the system’s operator. For the three and nine months ended September 30, 2025, gathering system operating costs were constant compared to the same period in 2024.

### Depletion, Depreciation, Amortization and Accretion (“DD&A”)

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| **Depletion, depreciation, amortization and accretion** | **​** | **$2,570,462** | ​ | **$2,698,812** | **​** | **$9,247,973** | ​ | **$7,127,641** |

Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves. For natural gas and oil development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves.

Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements, computer hardware. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 years. Also included in depreciation expense is an amount pertaining to buildings owned by the Company. Depreciation for the buildings is calculated using the straight-line method over an estimated useful life of 30 years.

Accretion expense is related to the asset retirement costs.

DD&A expense for the nine months ended September 30, 2025 increased by $2.1 million, or 30%, respectively, from the same period in 2024. This increase was a result of higher produced volumes in Pennsylvania. DD&A expense for the three months ended September 30, 2025 was constant from the same period in 2024.

### Impairment

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| **Impairment** | **​** | **$—** | ​ | **$—** | **​** | **$2,676,669** | ​ | **$—** |

We perform a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the market forward prices, timing, methods and other assumptions consistent with historical periods. When indicators of impairment are present, GAAP requires that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair value is required. Additionally, GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, should be charged to expense.

For the nine months ended September 30, 2025, the Company recorded an impairment of $2.7 million for two wells drilled in Alberta, Canada. The impairment was a result of a decrease in estimated reserves due to early production coming in below expectations, cost overruns and lower forward commodity prices. For the three months ended September 30, 2025, there was no impairment. For the three and nine months ended September 30, 2024, there was no impairment.

### General and Administrative (“G&A”)

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| **General and administrative** | **​** | **$2,844,398** | ​ | **$1,758,685** | **​** | **$6,896,370** | ​ | **$5,431,081** |

G&A expenses consist of general corporate expenses such as compensation, legal, accounting and professional fees, consulting services, travel and other related corporate costs such as restricted stock granted.

G&A expenses for the three and nine months ended September 30, 2025 increased by $ 1.1 million, or 62%, and $1.5 million, or 27%, respectively, from the same period in 2024. This was primarily due to transaction expenses of $0.9 million related to the pending Peak acquisition.

### Interest Income

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| **Interest income** | **​** | **$84,894** | **​** | **$60,693** | **​** | **$117,440** | **​** | **$435,908** |

Interest income for the three and nine months ended September 30, 2025 decreased by $0.01 million, or 12%, and $0.4 million, or 75%, respectively, from the same period in 2024. This was primarily due to a reduction in the balance of cash and short term investments.

### Interest Expense

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| **Interest expense** | **​** | **$11,666** | ​ | $17,598 | **​** | **$43,783** | ​ | $35,117 |

Interest expense is related to the fees paid on the revolving credit facility.

Interest expense during the three and nine months ended September 30, 2025 and 2024 was relatively flat.

### Gain (Loss) on Derivative Contracts

| ​ ​ ​ | ​ ​ | ​ ​ Three months ended September 30, 2025 | ​ | ​ ​ 2024 | ​ ​ | ​ ​ Nine months ended September 30, 2025 | ​ | ​ ​ 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| **Gain on derivative contracts** | **​** | **$964,307** | **​** | **$440,712** | **​** | **$2,076,000** | **​** | **$245,095** |

For the nine months ended September 30, 2025, Epsilon had NYMEX HH Natural Gas futures swaps, Tennessee Gas Pipeline Zone 4 basis swaps, NYMEX HH options, and crude oil NYMEX WTI CMA swaps derivative contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue. The amounts recorded represent the fair value changes on our derivative instruments during the year.

During the three and nine months ended September 30, 2025, we received net cash settlements of $807,648 and $699,265, respectively. During the three and nine months ended September 30, 2024, we received net cash settlements of $485,389 and $1,245,931, respectively.

For the three and nine months ended September 30, 2025, realized gains on derivative contracts increased by $0.5 million and $1.8 million, respectively. This increase was primarily the result of a significant decrease in Henry Hub natural gas prices and WTI crude oil prices during the year.

### Capital Resources and Liquidity

### Cash Flow

The primary source of cash for Epsilon during the three and nine months ended September 30, 2025 and 2024 was funds generated from operations. The primary uses of cash for the three and nine months ended September 30, 2025 were the development of upstream properties and the distribution of dividends. The primary uses of cash for the three and nine months ended September 30, 2024 were the development of upstream properties, investment in U.S. Treasury Bills, the repurchase of shares of common stock, and the distribution of dividends.

At September 30, 2025, we had a working capital surplus of $9.2 million, an increase of $2.0 million from the $7.2 million surplus at December 31, 2024. The Company anticipates its current cash balance, available borrowings, and cash flows from operations to be sufficient to meet its cash requirements for at least the next twelve months.

#### Nine months ended September 30, 2025 compared to 2024

During the nine months ended September 30, 2025, $20.9 million was provided by the Company’s operating activities, compared to $11.8 million during the same period in 2024, representing an 77% increase. The increase was primarily due to higher produced volumes and realized prices in Pennsylvania.

The Company used $10.4 million and $11 million of cash for investing activities during the nine months ended September 30, 2025 and 2024, respectively. During the nine months ended September 30, 2025, the Company had net investments of $10.4 million primarily in well costs and leasehold in Pennsylvania, Texas, and Canada. During the nine months ended September 30, 2024, the Company had net investments of $30.1 million in leasehold and well costs in Pennsylvania, Texas and Canada offset by net proceeds of $19.1 million in U.S. Treasury Bills.

The Company used $4.1 million and $5.9 million of cash for financing activities during the nine months ended September 30, 2025 and 2024, respectively. During the nine months ended September 30, 2025, this was spent on dividend payments. During the nine months ended September 30, 2024, this was spent on dividend payments and the repurchase of shares of common stock.

### Credit Agreement

The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender. The borrowing base at September 30, 2025 was $45 million (redetermined as of February 10, 2025), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of June 28, 2027. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower). There are currently no borrowings under the facility.

Under the terms of the facility, the Company must adhere to the following financial covenants:

- Current ratio of 1.0 to 1.0 (current assets / current liabilities)
- Leverage ratio of less than 2.5 to 1.0 (total debt / income adjusted for interest, taxes and non-cash amounts)

Additionally, if the Leverage ratio is greater than 1.0 to 1.0, or the borrowing base utilization is greater than 50%, the Company is required to hedge 50% of the anticipated production from PDP reserves for a rolling 24 month period.

On October 8, 2025, the Company closed a new senior secured reserve based revolving credit facility with Frost Bank as administrative agent and Frost Bank and Texas Capital Bank as lenders (replacing the previous credit facility). The borrowing base was initially set at $45 million, supported by the Company’s upstream assets and subject to semi-annual redeterminations with a maturity date of October 8, 2029. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3-4%. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower) and the Company was added as a co-borrower. There are currently no borrowings under the facility.

Under the terms of the facility, the Company must adhere to the following financial covenants:

- Current ratio of 1.0 to 1.0 (current assets / current liabilities)
- Leverage ratio of less than 2.5 to 1.0 (total debt / income adjusted for interest, taxes and noncash amounts)

Additionally, once the facility is drawn, the Company is required to hedge 50% of the anticipated production from PDP reserves for a rolling 18-month period (reduces to 25% on the last 6 months if the facility utilization is \<50% of the borrowing base).

### Repurchase Transactions

On February 12, 2025, Epsilon’s board of directors (the “Board”) authorized a new share repurchase program of up to 2,200,876 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $13.0 million. The program commenced on February 12, 2025 and ends on February 11, 2026, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.

The previous share repurchase program commenced on March 19, 2024. During the year ended December 31, 2024, we repurchased 125,000 common shares and spent $627,500 at an average price of $5.00 per share (excluding commissions) under the plan. On February 12, 2025, the Board terminated and revoked authority under the program.

During the nine months ended September 30, 2025, no shares were repurchased under the new or previous program.

### Derivative Transactions

The Company has entered into hedging arrangements to reduce the impact of commodity price volatility on operations. By reducing the price volatility from a portion of natural gas and crude oil production, the potential effects of changing prices on operating cash flows have been partially mitigated, but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices.

At September 30, 2025, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:

| ​ ​ ​ ​ ​ ​ Derivative Type 2025 ​ | ​ ​ Volume (MMbtu) ​ | ​ ​ ​ ​ | ​ ​ Weighted Average Price ($/Mmbtu) ​ ​ Swaps ​ ​ | ​ ​ ​ | ​ ​ Ceiling Price ​ ​ | ​ ​ ​ | ​ ​ Floor Price ​ ​ | ​ ​ ​ | ​ ​ Basis Differential ​ ​ | ​ ​ ​ ​ | ​ ​ ​ ​ Fair Value of Asset September 30, 2025 ​ ​ |
| --- | ---: | --- | ---: | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Henry Hub Nymex Swap | 183,000 | ​ | $4.66 | ​ | $— | ​ | $— | ​ | $— |  | $193,937 |
| Henry Hub Nymex Option - Put | 262,000 | ​ | $— | ​ | $— | ​ | $3.47 | ​ | $— |  | $74,393 |
| Henry Hub Nymex Option - Call | — | ​ | $— | ​ | $5.65 | ​ | $— | ​ | $— |  | $(9,659) |
| 2026 | ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Henry Hub Nymex Swap | 912,000 | ​ | $4.27 | ​ | $— | ​ | $— | ​ | $— |  | $417,827 |
| Henry Hub Nymex Option - Put | 1,345,300 | ​ | $— | ​ | $— | ​ | $3.80 | ​ | $— |  | $411,163 |
| Henry Hub Nymex Option - Call | — | ​ | $— | ​ | $4.86 | ​ | $— | ​ | $— |  | $(338,906) |
| 2027 | ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Henry Hub Nymex Option - Put | 579,400 | ​ | $— | ​ | $— | ​ | $3.30 | ​ | $— |  | $209,824 |
| Henry Hub Nymex Option - Call | — | ​ | $— | ​ | $5.40 | ​ | $— | ​ | $— |  | $(224,921) |
| ​ | 3,281,700 | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |  | $733,658 |

| ​ ​ ​ Derivative Type 2025 | ​ ​ ​ ​ | ​ ​ Volume (Bbl) ​ | ​ ​ ​ ​ | ​ ​ ​ Weighted Average Price ($/Bbl) ​ ​ | ​ ​ ​ ​ | ​ ​ Fair Value September 30, 2025 ​ ​ |
| --- | --- | ---: | --- | ---: | --- | ---: |
| Crude Oil NYMEX WTI CMA |  | 21,800 | ​ | $67.66 |  | $125,226 |
| 2026 | ​ | ​ | ​ | ​ ​ | ​ | ​ ​ |
| Crude Oil NYMEX WTI CMA |  | 9,000 | ​ | $67.12 |  | $30,303 |
| ​ |  | 30,800 | ​ | ​ ​ | ​ | $155,529 |

### Contractual Obligations

The Company enters into commitments for capital expenditures in advance of the expenditures being made. As of September 30, 2025, the Company has commitments of $0.2 million for capital expenditures and has undiscounted long term commitments of $15.8 million for asset retirement obligations.

## Market risk

As filed, 2,343 characters.

Our earnings and cash flow are significantly affected by changes in the market price of commodities. The prices of natural gas and oil can fluctuate widely and are influenced by numerous factors such as demand, production levels, world political and economic events, and the strength of the US dollar relative to other currencies. Should the price of natural gas and oil decline substantially, the value of our assets could fall dramatically, impacting our future operations and exploration and development activities, along with our gas gathering system revenues. In addition, our operations are exposed to market risks in the ordinary course of our business, including interest rate and certain exposure as well as risks relating to changes in the general economic conditions in the United States.

### Gathering System Revenue Risk

The Auburn Gas Gathering System lies within the Marcellus Basin with historically high levels of recoverable reserves and low cost of production. We believe that a short-term low commodity price environment will not significantly impact the reserves produced and thus the revenue of our gas gathering system.

### Interest Rate Risk

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding balance under our credit agreement. The credit agreement allows us to fix the interest rate.

At September 30, 2025 and 2024, the outstanding principal balance under the credit agreement was nil.

### Derivative Contracts

The Company’s financial results and condition depend on the prices received for production. Natural gas, natural gas liquids, and crude oil prices have fluctuated widely and are determined by economic and political factors. Supply and demand factors, including weather, general economic conditions, the ability to transport to other regions, as well as conditions in other regions, impact prices. Epsilon has established a hedging strategy and may manage the risk associated with changes in commodity prices by entering into various derivative financial instrument agreements and physical contracts. Although these commodity price risk management activities could expose Epsilon to losses or gains, entering into these contracts helps to stabilize cash flows and support the Company’s capital spending program.

## Controls and procedures

As filed, 2,397 characters.

### Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our chief executive officer and chief financial officer have concluded that our current disclosure controls and procedures were effective as of September 30, 2025 at the reasonable assurance level.

### Changes in Internal Control over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended September 30, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

### Inherent Limitations on Effectiveness of Controls

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting can also be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that of limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, the risk.

## Risk factors

As filed, 164 characters.

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2024.

Filed Nov 5, 2025.
Source: SEC EDGAR, the filing index for accession 0001104659-25-106988. Last ingested by Listed: Oct 24, 2026, 15:15 ET. No prices; not investment advice.