Epsilon Energy Ltd.
08/12/2026 | Press release | Distributed by Public on 08/12/2026 15:09
Quarterly Report for Quarter Ending June 30, 2026 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 June 30, 2026 and 2025 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, 2025. 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 areas of operations are the Appalachian Basin in Pennsylvania, the Powder River Basin in Wyoming, the Permian Basin in Texas and New Mexico, and the Western Canadian Sedimentary Basin in Alberta, Canada.
At June 30, 2026 we held leasehold rights to 52,290 net acres. We have natural gas production from our non-operated wells in Pennsylvania and natural gas, natural gas liquids, and oil production from our operated and non-operated wells in the Permian, Powder River, and Western Canadian Sedimentary Basins.
At December 31, 2025 our total estimated net proved reserves were 86.4 Bcf of natural gas reserves, 9.3 MMBbls of oil reserves, and 2.4 MMBbls of NGL reserves.
Our Pennsylvania ("PA") assets are supported by our 35% ownership in the Auburn GGS.
Our common shares trade on the NASDAQ Global Market under the ticker symbol "EPSN."
Business Strategy
We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or 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.
On November 14, 2025, Epsilon acquired Peak Exploration and Production LLC and Peak BLM Lease LLC and their subsidiaries (together, "Peak") through a business combination. The acquisition added 284 gross (60 net) wells, including 105 gross (45 net) operated wells, and 60,945 gross (39,566 net) acres located in Campbell, Converse and Johnson Counties, Wyoming.
On December 11, 2025, Epsilon divested Dewey Energy Holdings, LLC, a wholly owned subsidiary of the Company to an undisclosed private buyer. The assets sold included approximately 964 Mcfe/d (60% natural gas) of production and approximately 6,400 net deep acres and 2,200 net shallow acres of leasehold, all located in Dewey County, Oklahoma.
On May 4, 2026, the Company divested certain overriding royalty interests (ORRIs) in Susquehanna Co, Pennsylvania to an undisclosed private buyer for $3.9 million. The assets covered 940 gross acres and 90 producing Marcellus wells with an average net revenue interest of 0.25% per well.
We have a substantial remaining drillable location inventory within our existing leaseholds in Pennsylvania, Wyoming, and Texas.
Three and six months ended June 30, 2026 Highlights
Operational Highlights
Marcellus Shale - Pennsylvania
| ● | During the three months ended June 30, 2026, Epsilon's realized natural gas price was $2.01 per Mcf, a 21% decrease over the three months ended June 30, 2025. During the six months ended June 30, 2026, Epsilon's realized natural gas price was $4.06 per Mcf, a 26% increase over the six months ended June 30, 2025. |
| ● | During the three months ended June 30, 2026, Epsilon's net revenue interest natural gas production was 1.8 Bcf, a 32% decrease over the three months ended June 30, 2025. During the six months ended June 30, 2026, Epsilon's net revenue interest natural gas production was 3.9 Bcf, a 26% decrease over the six months ended June 30, 2025. |
| ● | Gathered and delivered 7.7 Bcf gross (2.7 net to Epsilon's interest) during the three months ended June 30, 2026, or 85 MMcf/d through the Auburn Gas Gathering System. Gathered and delivered 17.3 Bcf gross (6.1 net to Epsilon's interest) during the six months ended June 30, 2026, or 95.6 MMcf/d through the Auburn Gas Gathering System. |
Powder River Basin - Wyoming
| ● | During the three months ended June 30, 2026, Epsilon's realized price for all Powder River Basin production was $61.28 per Boe (75% liquids). During the six months ended June 30, 2026, Epsilon's realized price for all Powder River Basin production was $55.20 per Boe (74% liquids). |
| ● | Total net revenue interest production for the three months ended June 30, 2026, which included oil, natural gas liquids, and natural gas, was 158.4 Mboe. Total net revenue interest production for the six months ended June 30, 2026, which included oil, natural gas liquids, and natural gas, was 338.1 Mboe. |
Permian Basin - Texas and New Mexico
| ● | During the three months ended June 30, 2026, Epsilon's realized price for all Permian Basin production was $66.13 per Boe (87% liquids), a 28% increase over the three months ended June 30, 2025. During the six months ended June 30, 2026, Epsilon's realized price for all Permian Basin production was $57.23 per Boe (86% liquids), a 7% increase over the six months ended June 30, 2025. |
| ● | Total net revenue interest production for the three months ended June 30, 2026, which included oil, natural gas liquids, and natural gas, was 52.0 Mboe compared to 42.9 Mboe during the same period in 2025, a 21% increase. Total net revenue interest production for the six months ended June 30, 2026, which included oil, natural gas liquids, and natural gas, was 103.7 Mboe compared to 104.9 Mboe during the same period in 2025, a 1% decrease. |
| ● | During the three and six months ended June 30, 2026, the Company had 1 gross (.25 net) well completed and turned in line. |
Western Canadian Sedimentary Basin-Alberta, Canada
| ● | During the three months ended June 30, 2026, Epsilon's realized price for all Canada production was $31.02 per Boe (51% liquids). During the six months ended June 30, 2026, Epsilon's realized price for all Canada production was $29.49 per Boe (50% liquids). |
| ● | Total net revenue interest production for the three months ended June 30, 2026, which included oil, natural gas liquids, and natural gas, was 5.6 Mboe. Total net revenue interest production for the six months ended June 30, 2026, which included oil, natural gas liquids, and natural gas, was 11.3 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) transaction costs, (7) gain or loss on derivative contracts net of cash received or paid on settlement, (8) gain or lss on sale of assets, and (9) gain or loss on foreign currency traslations. 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 six months ended June 30, 2026 and 2025, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully.
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Three months ended June 30, |
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Six months ended June 30, |
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|
2026 |
2025 |
2026 |
2025 |
|||||||
|
Net income |
|
$ |
7,133,471 |
|
$ |
1,551,461 |
|
$ |
7,862,896 |
|
$ |
5,567,495 |
|
Add Back: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense (income), net |
|
|
852,482 |
|
|
2,659 |
|
|
1,748,521 |
|
|
(429) |
|
Income tax expense |
|
|
2,429,235 |
|
|
1,837,687 |
|
|
2,696,971 |
|
|
3,507,881 |
|
Depreciation, depletion, amortization, and accretion |
|
|
2,804,107 |
|
|
3,201,654 |
|
|
5,806,446 |
|
|
6,677,511 |
|
Impairment expense |
|
|
- |
|
|
2,670,000 |
|
|
- |
|
|
2,676,669 |
|
Stock based compensation expense |
|
|
547,527 |
|
|
385,838 |
|
|
1,095,054 |
|
|
771,676 |
|
Gain on sale of oil and gas properties |
|
|
(4,174,368) |
|
|
- |
|
|
(4,174,368) |
|
|
- |
|
Transaction costs |
|
|
202,532 |
|
|
- |
|
|
273,952 |
|
|
- |
|
(Gain)/loss on derivative contracts net of cash received or paid on settlement |
|
|
(3,976,251) |
|
|
(2,267,203) |
|
|
3,905,742 |
|
|
(1,220,076) |
|
Foreign currency translation (gain) loss |
|
|
(1,201) |
|
|
14,021 |
|
|
(3,076) |
|
|
24,310 |
|
Adjusted EBITDA |
|
$ |
5,817,534 |
|
$ |
7,396,117 |
|
$ |
19,212,138 |
|
$ |
18,005,037 |
Results of Operations
Net Operating Revenues
For the six months ended June 30, 2026, revenues increased $16.1 million, or 58%, to $43.9 million from $27.8 million during the same period of 2025.
Revenue and volume statistics for the six months ended June 30, 2026 and 2025 were as follows:
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Three months ended |
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Six months ended |
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June 30, |
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June 30, |
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2026 |
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2025 |
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2026 |
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2025 |
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Revenues |
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Pennsylvania |
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Natural gas revenue |
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$ |
3,602,852 |
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$ |
6,702,131 |
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$ |
15,915,420 |
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$ |
17,030,025 |
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Volume (MMcf) |
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1,792 |
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2,653 |
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3,924 |
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5,290 |
||||
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Avg. Price ($/Mcf) |
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$ |
2.01 |
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$ |
2.53 |
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$ |
4.06 |
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$ |
3.22 |
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Gathering system revenue (net of elimination) |
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$ |
1,336,740 |
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$ |
1,845,005 |
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$ |
2,994,517 |
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$ |
3,737,355 |
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Total PA Revenues |
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$ |
4,939,592 |
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$ |
8,547,136 |
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$ |
18,909,937 |
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$ |
20,767,380 |
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Permian Basin |
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Natural gas revenue |
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$ |
(167,957) |
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$ |
17,189 |
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$ |
(187,576) |
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$ |
95,528 |
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Volume (MMcf) |
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39 |
|
30 |
|
87 |
|
80 |
||||
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Avg. Price ($/Mcf) |
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$ |
(4.27) |
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$ |
0.56 |
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$ |
(2.16) |
|
$ |
1.19 |
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Natural gas liquids revenue |
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$ |
237,859 |
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$ |
41,837 |
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$ |
423,191 |
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$ |
326,798 |
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Volume (MBoe) |
|
10.4 |
|
3.2 |
|
21.1 |
|
15.3 |
||||
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Avg. Price ($/Bbl) |
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$ |
22.94 |
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$ |
13.06 |
|
$ |
20.02 |
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$ |
21.36 |
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Oil and condensate revenue |
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$ |
3,368,045 |
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$ |
2,163,481 |
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$ |
5,700,682 |
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$ |
5,182,976 |
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Volume (MBbl) |
|
35.1 |
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34.6 |
|
68.1 |
|
76.2 |
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Avg. Price ($/Bbl) |
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$ |
96.06 |
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$ |
62.47 |
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$ |
83.67 |
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$ |
68.06 |
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Total Permian Basin Revenues |
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$ |
3,437,947 |
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$ |
2,222,507 |
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$ |
5,936,297 |
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$ |
5,605,302 |
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Oklahoma |
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|
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|
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Natural gas revenue |
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$ |
17 |
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$ |
166,635 |
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$ |
10,092 |
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$ |
373,975 |
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Volume (MMcf) |
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(0) |
|
52 |
|
1 |
|
105 |
||||
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Avg. Price ($/Mcf) |
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$ |
(17.00) |
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$ |
3.20 |
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$ |
10.44 |
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$ |
3.57 |
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Natural gas liquids revenue |
|
$ |
429 |
|
$ |
79,789 |
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$ |
3,183 |
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$ |
182,078 |
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Volume (MBoe) |
|
0.0 |
|
3.7 |
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0.1 |
|
7.4 |
||||
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Avg. Price ($/Bbl) |
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$ |
22.14 |
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$ |
21.61 |
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$ |
30.65 |
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$ |
24.64 |
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Oil and condensate revenue |
|
$ |
- |
|
$ |
133,446 |
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$ |
384 |
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$ |
291,383 |
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Volume (MBbl) |
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(0.0) |
|
2.0 |
|
(0.5) |
|
4.3 |
||||
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Avg. Price ($/Bbl) |
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$ |
- |
|
$ |
66.00 |
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$ |
(0.82) |
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$ |
68.29 |
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Total OK Revenues |
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$ |
446 |
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$ |
379,870 |
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$ |
13,659 |
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$ |
847,436 |
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Wyoming |
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Natural gas revenue |
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$ |
315,269 |
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$ |
- |
|
$ |
1,383,572 |
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$ |
- |
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Volume (MMcf) |
|
235 |
|
- |
|
518 |
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- |
||||
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Avg. Price ($/Mcf) |
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$ |
1.34 |
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$ |
- |
|
$ |
2.67 |
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$ |
- |
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Natural gas liquids revenue |
|
$ |
1,118,839 |
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$ |
- |
|
$ |
1,978,807 |
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$ |
- |
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Volume (MBoe) |
|
30.6 |
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- |
|
61.0 |
|
- |
||||
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Avg. Price ($/Bbl) |
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$ |
36.54 |
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$ |
- |
|
$ |
32.45 |
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$ |
- |
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Oil and condensate revenue |
|
$ |
8,275,408 |
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$ |
- |
|
$ |
15,300,705 |
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$ |
- |
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Volume (MBbl) |
|
88.7 |
|
- |
|
190.8 |
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- |
||||
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Avg. Price ($/Bbl) |
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$ |
93.27 |
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$ |
- |
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$ |
80.18 |
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$ |
- |
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Total WY Revenues |
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$ |
9,709,516 |
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$ |
- |
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$ |
18,663,084 |
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$ |
- |
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Canada |
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Natural gas revenue |
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$ |
17,316 |
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$ |
24,389 |
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$ |
48,511 |
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$ |
24,389 |
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Volume (MMcf) |
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16 |
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17 |
|
34 |
|
16.98 |
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Avg. Price ($/Mcf) |
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$ |
1.06 |
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$ |
- |
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$ |
1.44 |
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$ |
- |
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Natural gas liquids revenue |
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$ |
29,762 |
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$ |
23,394 |
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$ |
55,009 |
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$ |
23,394 |
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Volume (MBoe) |
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1.1 |
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39.4 |
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2.3 |
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39.45 |
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Avg. Price ($/Bbl) |
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$ |
27.34 |
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$ |
- |
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$ |
24.23 |
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$ |
- |
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Oil and condensate revenue |
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$ |
127,077 |
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$ |
427,437 |
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$ |
230,946 |
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$ |
519,972 |
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Volume (MBbl) |
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1.8 |
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7.5 |
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3.4 |
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9.3 |
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Avg. Price ($/Bbl) |
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$ |
70.72 |
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$ |
57.11 |
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$ |
67.02 |
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$ |
55.98 |
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Total Canada Revenues |
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$ |
174,155 |
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$ |
475,220 |
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$ |
334,466 |
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$ |
567,755 |
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Total Revenues |
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$ |
18,261,656 |
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$ |
11,624,733 |
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$ |
43,857,443 |
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$ |
27,787,873 |
Upstream natural gas revenue for the six months ended June 30, 2026 decreased by $0.4 million, or 2%, over the same period in 2025. An increase of $2.6 million was due to higher natural gas prices and a decrease of $3.0 million was a result of decrease in volume due to the natural decline in the producing wells and the sale of the Oklahoma assets partially offset due to increased volumes as a result of the Peak acquisition. Upstream natural gas revenue for the three months ended June 30, 2026 decreased by $3.1 million, or 45%, over the same period in 2025. A decrease of $1.4 million was due
to lower natural gas prices and a decrease of $1.7 million was a result of decrease in volume due to the natural decline in the producing wells and the sale of the Oklahoma assets partially offset due to increased volumes as a result of the Peak acquisition.
Upstream natural gas liquids revenue for the six months ended June 30, 2026 increased by $1.9 million, or 362%, over the same period in 2025. This increase was primarily due to increased volumes as a result of the Peak acquisition. Upstream natural gas liquids revenue for the three months ended June 30, 2026 increased by $1.2 million, or 856%, over the same period in 2025. This increase was primarily due to increased volumes as a result of the Peak acquisition.
Upstream oil and condensate revenue for the six months ended June 30, 2026 increased by $15.2 million, or 254% over the same period in 2025. An increase of $11.5 million was due to higher volumes as a result of the Peak acquisition and an increase of $3.7 million was due to an increase in prices for oil in the Permian Basin. Upstream oil and condensate revenue for the three months ended June 30, 2026 increased by $9.0 million, or 332% over the same period in 2025. An increase of $5.0 million was due to higher volumes as a result of the Peak acquisition and an increase of $4.0 million was due to an increase in prices for oil in the Permian Basin.
Gathering system revenue for the six months ended June 30, 2026 decreased by $0.7 million, or 20%, compared with the same period in 2025 due to lower throughput volumes partially offset due to higher contractual rates for gathering and compression. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $0.8 million and $1.9 million, respectively, for the six months ended June 30, 2026 and 2025. Gathering system revenue for the three months ended June 30, 2026 decreased by $0.5 million, or 28%, compared with the same period in 2025 due to lower throughput volumes partially offset due to higher contractual rates for gathering and compression. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $0.4 million and $0.5 million, respectively, for the three months ended June 30, 2026 and 2025.
Operating Costs
The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the three and six months ended June 30, 2026 and 2025:
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Three months ended June 30, |
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Six months ended June 30, |
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|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
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Lease operating costs (net of elimination) |
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$ |
6,330,193 |
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$ |
2,462,785 |
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$ |
13,525,506 |
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$ |
5,218,683 |
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Gathering system operating costs |
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|
508,475 |
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|
613,795 |
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|
1,102,921 |
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|
1,166,446 |
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|
|
$ |
6,838,668 |
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$ |
3,076,580 |
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$ |
14,628,427 |
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$ |
6,385,129 |
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Upstream operating costs-Total $/Mcfe |
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$ |
2.05 |
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$ |
0.80 |
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$ |
2.04 |
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$ |
0.85 |
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Gathering system operating costs $/Mcf |
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$ |
0.18 |
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$ |
0.15 |
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$ |
0.18 |
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$ |
0.14 |
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 six months ended June 30, 2026 these costs increased by $8.3 million, or 159%, over the same period in 2025. The increase is primarily due to the Wyoming assets inclusion following the Peak acquisition (higher operating costs per unit relative to the other asset areas), workover expenses in Pennsylvania, and Ad Valorem taxes in Texas. For the three months ended June 30, 2026 these costs increased by $3.9 million, or 157%, over the same period in 2025. The increase is primarily due to the Wyoming assets inclusion following the Peak acquisition (higher operating costs per unit relative to the other asset areas).
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 six months ended June 30, 2026, gathering system operating costs were constant compared to the same period in 2025.
Depletion, Depreciation, Amortization and Accretion ("DD&A")
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Three months ended June 30, |
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Six months ended June 30, |
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|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Depletion, depreciation, amortization and accretion |
|
$ |
2,804,107 |
|
$ |
3,201,654 |
|
$ |
5,806,446 |
|
$ |
6,677,511 |
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, and 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 three and six months ended June 30, 2026 decreased by $0.4 million, or 12%, and $0.9 million, or 13%, respectively, from the same period in 2025. This decrease was a result of higher reserves and lower production in Pennsylvania and Texas and the sale of the Oklahoma assets (offset by the addition of the Wyoming assets).
Impairment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Impairment |
|
$ |
- |
|
$ |
2,670,000 |
|
$ |
- |
|
$ |
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 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 three and six months ended June 30, 2026, there was no impairment. For the three and six months ended June 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.
Gain on sales of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Gain on sale of oil and gas properties |
|
$ |
(4,174,368) |
|
$ |
- |
|
$ |
(4,174,368) |
|
$ |
- |
For the three and six months ended June 30, 2026, the Company sold its overriding royalty interests (ORRIs) in Susquehanna Co, Pennsylvania for $3.9 million and a wellbore interest in Texas for $0.3 million. There were no property sales for the three and six months ended June 30, 2025.
Transaction Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Transaction Costs |
|
$ |
202,532 |
|
$ |
- |
|
$ |
273,952 |
|
$ |
- |
For the three and six months ended June 30, 2026, the Company had transaction costs related to the Peak acquisition of $0.2 million and $0.3 million, respectively, for advisory and legal services incurred by the Company. For the three and six months ended June 30, 2025, there were no transaction costs.
General and Administrative ("G&A")
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
General and administrative expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation expense |
|
$ |
547,527 |
|
$ |
385,838 |
|
$ |
1,095,054 |
|
$ |
771,676 |
|
Other general and administrative expense |
|
|
3,664,814 |
|
|
1,461,878 |
|
|
7,042,956 |
|
|
3,280,296 |
|
Total general and administrative expenses |
|
$ |
4,212,341 |
|
$ |
1,847,716 |
|
$ |
8,138,010 |
|
$ |
4,051,972 |
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 six months ended June 30, 2026 increased by $2.4 million, or 128%, and $4.1 million, or 101%, respectively, from the same period in 2025. This was primarily due to increased compensation expenses related to the addition of 17 full-time employees as a result of the Peak acquisition and 6 former Peak employees on transition services contracts. As of June 1, 2026, the transition services contracts ended for 5 former Peak employees.
Interest Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Interest income |
|
$ |
24,785 |
|
$ |
17,247 |
|
$ |
70,327 |
|
$ |
32,546 |
Interest income for the six months ended June 30, 2026 increased by $0.04 million, or 116%, from the same period in 2025. This was primarily due to an increase in the balance of interest-bearing investments.
Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Interest expense |
|
$ |
877,267 |
|
$ |
19,906 |
|
$ |
1,818,848 |
|
$ |
32,117 |
Interest expense is related to the interest paid and amortization of debt issuance costs for the revolving credit facility.
Interest expense during the three and six months ended June 30, 2026 increased by $0.9 million, or 4,307%, and $1.8 million, or 5,563%, respectively, from the same period in 2025. This increase is related to the interest paid on the outstanding balance on the revolving credit facility.
Gain (Loss) on Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Gain (loss) on derivative contracts, net |
|
$ |
2,245,470 |
|
$ |
2,573,863 |
|
$ |
(6,684,358) |
|
$ |
1,111,693 |
During the six months ended June 30, 2026, the Company had NYMEX Henry Hub ("HH") Natural Gas Futures swaps, NYMEX HH options, crude oil NYMEX WTI CMA swaps, and crude oil NYMEX WTI CMA options derivative contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue.
For the six months ended June 30, 2025, Epsilon had NYMEX HH Natural Gas futures swaps, Tennessee Gas Pipeline Zone 4 basis swaps, 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 six months ended June 30, 2026, we paid net cash settlements of $1,730,781 and $2,778,616, respectively. During the three months ended June 30, 2025, we received net cash settlements of $306,660. During the six months ended June 30, 2025, we paid net cash settlements of $108,383.
For the three and six months ended June 30, 2026, realized losses on derivative contracts increased by $0.3 million and $7.8 million, respectively. This increase was primarily the result of a significant increase in crude oil prices during the quarter and its impact on the Peak hedge book assumed in the acquisition.
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
||||||||
|
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
||||
|
Other expense, net |
|
$ |
(208,658) |
|
$ |
(10,839) |
|
$ |
(192,230) |
|
$ |
(33,338) |
During the three and six months ended June 30, 2026, the Company had water facility expenses of $0.2 million in Wyoming.
Capital Resources and Liquidity
Cash Flow
The primary source of cash for Epsilon during the three and six months ended June 30, 2026 and 2025 was funds generated from operations. The primary uses of cash for the three and six months ended June 30, 2026 were the development of upstream properties, the reduction of the outstanding credit facility balance, and the distribution of dividends. The primary uses of cash for the three and six months ended June 30, 2025 were the development of upstream properties and the distribution of dividends.
At June 30, 2026, we had a working capital deficit of $1.3 million, a decrease of $8.9 million from the $7.6 million surplus at December 31, 2025. 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.
Six months ended June 30, 2026 compared to 2025
During the six months ended June 30, 2026, $22.4 million was provided by the Company's operating activities, compared to $16.9 million during the same period in 2025, representing an 32% increase. The increase was primarily due to produced oil volumes from the acquired Wyoming assets and higher realized gas prices in Pennsylvania.
The Company used $6.4 million and $10.7 million of cash for investing activities during the six months ended June 30, 2026 and 2025, respectively. During the six months ended June 30, 2026, the Company had $net investments primarily in well and facilities costs and leasehold in Pennsylvania, Texas, and Wyoming offset by the ORRI sale in Pennsylvania. During the six months ended June 30, 2025, the Company had net investments primarily in well costs in Pennsylvania, Texas, and Canada.
The Company used $13.8 million and $2.8 million of cash for financing activities during the six months ended June 30, 2026 and 2025, respectively. During the six months ended June 30, 2026, this was spent on the repayment of the outstanding balance on the credit facility and dividend payments. During the six months ended June 30, 2025, this was spent on dividend payments.
Credit Agreement
The Company closed a new senior secured reserve based revolving credit facility on October 10, 2025 with Frost Bank as administrative agent and Frost Bank and Texas Capital Bank as lenders. This replaced the Company's previous credit facility. As of June 30, 2026, the borrowing base was $90 million, supported by the Company's producing reserves and is subject to semi-annual redeterminations with a maturity date of October 10, 2029. Interest will be charged at the 3-month Term SOFR rate plus a margin of 3-4% (depending on facility utilization), payable quarterly. The facility is secured by the assets of the Company's Epsilon Energy USA subsidiary. During the six months ended June 30, 2026, the Company made repayments of $10 million on the outstanding credit facility. The current balance as of August 12, 2026 is $40.5 million.
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 + revolver availability / current liabilities) |
| ● | Leverage ratio of less than 2.5 to 1.0 (total debt / income adjusted for interest, taxes and non-cash amounts) |
Additionally, the Company is required to hedge 50% of its forecasted Proved Developed Producing production over a rolling 18-month period. If the facility utilization drops below 50%, then the required hedging drops to 25% of Proved Developed Producing production for the last 6 months of the 18-month period.
Repurchase Transactions
On February 18, 2026, the Board authorized a new share repurchase program of up to 3,014,986 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $15.0 million. The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on February 19, 2026 and will end on February 18, 2027, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.
On February 12, 2025, the Board authorized a new share repurchase program of up to 2,200,876 common shares, representing 10% of the outstanding common shares of the Company at such time, for an aggregate purchase price of not more than US $13.0 million. The program is pursuant to a normal course issuer bid and conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on February 12, 2025 and expired on February 11, 2026.
During the six months ended June 30, 2026, no shares were repurchased under the new or previous program.
Derivative Transactions
The Company has entered into hedging arrangements to reduce the impact of commodity price volatility on operations. By reducing the price volatility from a portion of natural gas and crude oil production, the potential effects of changing prices on operating cash flows have been partially mitigated but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices.
At June 30, 2026, Epsilon's outstanding natural gas and crude oil commodity contracts consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price ($/Mmbtu) |
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of |
|
|
|
|
Volume |
|
|
|
|
Ceiling |
|
Floor |
|
Asset (Liability) |
|||
|
Derivative Type |
|
(MMbtu) |
|
Swaps |
|
Price |
|
Price |
|
June 30, 2026 |
||||
|
2026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Henry Hub (LD) Options Call |
(1,144,794) |
|
$ |
- |
|
$ |
5.05 |
|
$ |
- |
$ |
(58,232) |
||
|
NYMEX Henry Hub (LD) Options Put |
- |
|
$ |
- |
|
$ |
- |
|
$ |
3.35 |
$ |
306,434 |
||
|
NYMEX Henry Hub (LD) Swaps |
(476,613) |
|
$ |
3.91 |
|
$ |
- |
|
$ |
- |
$ |
298,496 |
||
|
2027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Henry Hub (LD) Options Call |
(2,835,516) |
|
$ |
- |
|
$ |
4.71 |
|
$ |
- |
$ |
(529,236) |
||
|
NYMEX Henry Hub (LD) Options Put |
- |
|
$ |
- |
|
$ |
- |
|
$ |
3.19 |
$ |
1,142,995 |
||
|
NYMEX Henry Hub (LD) Swaps |
(312,297) |
|
$ |
3.76 |
|
$ |
- |
|
$ |
- |
$ |
101,034 |
||
|
2028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Henry Hub (LD) Options Call |
(27,978) |
|
$ |
- |
|
$ |
4.70 |
|
$ |
- |
$ |
(21,669) |
||
|
NYMEX Henry Hub (LD) Options Put |
- |
|
$ |
- |
|
$ |
- |
|
$ |
3.65 |
$ |
8,013 |
||
|
NYMEX Henry Hub (LD) Swaps |
(27,978) |
|
$ |
4.46 |
|
$ |
- |
|
$ |
- |
$ |
(6,707) |
||
|
|
(4,825,176) |
|
|
|
|
|
|
|
|
|
$ |
1,241,128 |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price ($/Bbl) |
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of |
|
|
|
|
Volume |
|
|
|
|
Ceiling |
|
Floor |
|
Asset (Liability) |
|||
|
Derivative Type |
|
(Bbl) |
|
Swaps |
|
Price |
|
Price |
|
June 30, 2026 |
||||
|
2026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX WTI CMA Options Call |
|
(28,109) |
|
$ |
- |
|
$ |
69.01 |
|
$ |
- |
$ |
(151,085) |
|
|
NYMEX WTI CMA Options Put |
|
- |
|
$ |
- |
|
$ |
- |
|
$ |
59.01 |
$ |
59,721 |
|
|
NYMEX WTI CMA Swaps |
|
(119,179) |
|
$ |
64.36 |
|
$ |
- |
|
$ |
- |
$ |
(536,868) |
|
|
2027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX WTI CMA Options Call |
|
(118,096) |
|
$ |
- |
|
$ |
67.82 |
|
$ |
- |
$ |
(808,558) |
|
|
NYMEX WTI CMA Options Put |
|
- |
|
$ |
- |
|
$ |
- |
|
$ |
57.60 |
$ |
471,814 |
|
|
NYMEX WTI CMA Swaps |
|
(105,986) |
|
$ |
63.76 |
|
$ |
- |
|
$ |
- |
$ |
(293,495) |
|
|
2028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX WTI CMA Options Call |
|
(8,308) |
|
$ |
- |
|
$ |
67.96 |
|
$ |
- |
$ |
(57,075) |
|
|
NYMEX WTI CMA Options Put |
|
- |
|
$ |
- |
|
$ |
- |
|
$ |
57.57 |
$ |
38,757 |
|
|
NYMEX WTI CMA Swaps |
|
(8,308) |
|
$ |
62.97 |
|
$ |
- |
|
$ |
- |
$ |
(20,805) |
|
|
|
(387,986) |
|
|
|
|
|
|
|
|
|
|
$ |
(1,297,594) |
|
Contractual Obligations
The following table summarizes our contractual obligations at June 30, 2026.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
||||||||||
|
|
|
|
|
|
Less than |
|
1 - 3 |
|
Greater than |
|||
|
|
|
Total |
|
1 Year |
|
Years |
|
3 Years |
||||
|
Derivative liabilities |
|
$ |
2,549,588 |
|
$ |
1,689,463 |
|
$ |
860,125 |
|
$ |
- |
|
Asset retirement obligations, undiscounted |
|
|
19,033,067 |
|
|
- |
|
|
- |
|
|
19,033,067 |
|
Capital expenditure commitments |
|
18,033,916 |
|
18,033,916 |
|
- |
|
- |
||||
|
Total future commitments |
|
$ |
39,616,571 |
|
$ |
19,723,379 |
|
$ |
860,125 |
|
$ |
19,033,067 |
The Company enters into commitments for capital expenditures in advance of the expenditures being made. As of June 30, 2026, our commitments for capital expenditures were $18 million related to the drilling and completion of 5 gross (0.37 net) wells in Pennsylvania and the completion of 6 gross (3.58 net) wells in Wyoming.
Epsilon Energy Ltd. published this content on August 12, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on August 12, 2026 at 21:11 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]