Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2025
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-38770
EPSILON ENERGY LTD.
(Exact name of registrant as specified in its charter)
Alberta, Canada
98-1476367
(State or other jurisdiction of incorporation or organization)
(I.R.S Employer Identification No.)
500 Dallas Street, Suite 1250
Houston, Texas 77002
(281) 670-0002
(Address of principal executive offices including zip code and
telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name of each exchange on which registered
Common Shares, no par value
EPSN
NASDAQ Global Market
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ⌧ No ◻
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ◻
Accelerated filer ◻
Non-accelerated filer ⌧
Smaller reporting company ☒
Emerging growth company ◻
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Yes ☐ No ⌧
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
As of November 4, 2025, there were 22,067,213 Common Shares outstanding.
Contents
FORWARD-LOOKING STATEMENTS
4
PART I-FINANCIAL INFORMATION
5
ITEM 1. FINANCIAL STATEMENTS
Unaudited Condensed Consolidated Balance Sheets
Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income
6
Unaudited Condensed Consolidated Statements of Changes in Shareholders’ Equity
7
Unaudited Condensed Consolidated Statements of Cash Flows
9
Notes to the Unaudited Condensed Consolidated Financial Statements
1.
Description of Business
10
2.
Basis of Preparation
Interim Financial Statements
Principles of Consolidation
Use of Estimates
Recently Issued Accounting Standards
11
3.
Cash, Cash Equivalents, and Restricted Cash
4.
Short Term Investments
12
5.
Property and Equipment
Property Impairment
13
6.
Revolving Line of Credit
7.
Shareholders’ Equity
14
8.
Revenue Recognition
15
9.
Accumulated Other Comprehensive Income
17
10.
Income Taxes
11.
Commitments and Contingencies
18
12.
Leases
13.
Net Income Per Share
19
14.
Operating Segments
15.
Commodity Risk Management Activities
23
Commodity Price Risks
Commodity Derivative Contracts
24
16.
Asset Retirement Obligations
25
17.
Fair Value Measurements
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
27
Overview
Business Strategy
Operational Highlights
28
Non-GAAP Financial Measures-Adjusted EBITDA
29
Net Operating Revenues
31
Operating Costs
32
Depletion, Depreciation, Amortization and Accretion
33
General and Administrative
Interest Income
34
Interest Expense
Gain (Loss) on Derivative Contracts
Capital Resources and Liquidity
Cash Flow
Credit Agreement
35
Repurchase Transactions
36
Derivative Transactions
Contractual Obligations
37
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Gathering System Revenue Risk
Interest Rate Risk
Derivative Contracts
38
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Changes in Internal Control Over Financial Reporting
Inherent Limitations on Effectiveness of Controls
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
ITEM 1A. RISK FACTORS
ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
39
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
ITEM 4. MINE SAFETY DISCLOSURES
ITEM 5. OTHER INFORMATION
ITEM 6. EXHIBITS
40
SIGNATURES
41
Certain statements contained in this report constitute forward-looking statements. The use of any of the words ‘‘anticipate,’’ ‘‘continue,’’ ‘‘estimate,’’ ‘‘expect,’’ ‘‘may,’’ ‘‘will,’’ ‘‘project,’’ ‘‘should,’’ ‘‘believe,’’ and similar expressions and statements relating to matters that are not historical facts constitute ‘‘forward looking information’’ within the meaning of applicable securities laws. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated. Such forward-looking statements are based on reasonable assumptions, but no assurance can be given that these expectations will prove to be correct and the forward-looking statements included in this report should not be unduly relied upon. These statements are made only as of the date of this report. All statements that address operating performance, events or developments that we expect or anticipate will occur in the future — including statements relating to natural gas and oil production rates, commodity prices for crude oil or natural gas, supply and demand for natural gas and oil; the estimated quantity of natural gas and oil reserves, including reserve life; future development and production costs, and statements expressing general views about future operating results — are forward-looking statements. Management believes that these forward-looking statements are reasonable as and when made. However, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date when made. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. In addition, forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from our present expectations or projections. These risks and uncertainties include, but are not limited to, those described in our Annual Report on Form 10-K for the year ended December 31, 2024, and those described from time to time in our future reports filed with the Securities and Exchange Commission. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2024. Our Annual Report on Form 10-K for the year ended December 31, 2024 is available on our website at www.epsilonenergyltd.com.
September 30,
December 31,
2025
2024
ASSETS
Current assets
Cash and cash equivalents
$
12,766,167
6,519,793
Accounts receivable
4,515,199
5,843,722
Fair value of derivatives
889,187
—
Prepaid income taxes
975,963
Other current assets
965,970
792,041
Total current assets
19,136,523
14,131,519
Non-current assets
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties
200,066,005
191,879,210
Unproved properties
33,396,744
28,364,186
Accumulated depletion, depreciation, amortization and impairment
(134,181,378)
(123,281,395)
Total oil and gas properties, net
99,281,371
96,962,001
Gathering system
43,540,301
43,116,371
(37,271,826)
(36,449,511)
Total gathering system, net
6,268,475
6,666,860
Land
637,764
Buildings and other property and equipment, net
221,901
259,335
Total property and equipment, net
106,409,511
104,525,960
Other assets:
Operating lease right-of-use assets, long term
272,298
344,589
Restricted cash
470,000
Prepaid drilling costs
4,673
982,717
Total non-current assets
107,156,482
106,323,266
Total assets
126,293,005
120,454,785
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable trade
2,963,805
2,334,732
Gathering fees payable
978,890
997,016
Royalties payable
1,481,520
1,400,976
Income taxes payable
1,556,724
Accrued capital expenditures
1,605,705
572,079
Accrued compensation
726,213
695,018
Other accrued liabilities
490,970
371,503
487,548
Operating lease liabilities
120,799
121,135
Total current liabilities
9,924,626
6,980,007
Non-current liabilities
Asset retirement obligations
3,822,030
3,652,296
Deferred income taxes
12,062,053
12,738,577
Operating lease liabilities, long term
266,263
355,776
Total non-current liabilities
16,150,346
16,746,649
Total liabilities
26,074,972
23,726,656
Commitments and contingencies (Note 11)
Shareholders' equity
Preferred shares, no par value, unlimited shares authorized, none issued or outstanding
Common shares, no par value, unlimited shares authorized and 22,058,574 shares issued and outstanding at September 30, 2025 and 22,008,766 issued and outstanding at December 31, 2024
116,081,031
Additional paid-in capital
13,267,196
12,118,907
Accumulated deficit
(38,995,173)
(41,505,076)
Accumulated other comprehensive income
9,864,979
10,033,267
Total shareholders' equity
100,218,033
96,728,129
Total liabilities and shareholders' equity
The accompanying notes are an integral part of these interim unaudited condensed consolidated financial statements
Three months ended September 30,
Nine months ended September 30,
Revenues from contracts with customers:
Gas, oil, NGL, and condensate revenue
7,536,248
6,203,953
31,586,766
18,118,368
Gas gathering and compression revenue
1,445,211
1,083,988
5,182,566
4,464,134
Total revenue
8,981,459
7,287,941
36,769,332
22,582,502
Operating costs and expenses:
Lease operating expenses
2,397,052
2,099,501
7,615,735
5,517,830
Gathering system operating expenses
563,542
490,325
1,729,988
1,692,862
Depletion, depreciation, amortization, and accretion
2,570,462
2,698,812
9,247,973
7,127,641
Impairment expense
2,676,669
General and administrative expenses:
Stock based compensation expense
376,613
309,109
1,148,289
944,267
Other general and administrative expenses
2,467,785
1,449,576
5,748,081
4,486,814
Total operating costs and expenses
8,375,454
7,047,323
28,166,735
19,769,414
Operating income
606,005
240,618
8,602,597
2,813,088
Other income (expense):
Interest income
84,894
60,693
117,440
435,908
Interest expense
(11,666)
(17,598)
(43,783)
(35,117)
Gain on derivative contracts, net
964,307
440,712
2,076,000
245,095
Other income (expense), net
5,252
9,994
(28,086)
111,067
Other income, net
1,042,787
493,801
2,121,571
756,953
Net income before income tax expense
1,648,792
734,419
10,724,168
3,570,041
Income tax expense
576,497
368,398
4,084,378
881,464
NET INCOME
1,072,295
366,021
6,639,790
2,688,577
Currency translation adjustments
(42,676)
39,845
(168,288)
62,438
Unrealized loss on securities
(1,598)
NET COMPREHENSIVE INCOME
1,029,619
405,866
6,471,502
2,749,417
Net income per share, basic
0.05
0.02
0.30
0.12
Net income per share, diluted
Weighted average number of shares outstanding, basic
22,017,310
21,948,519
22,028,248
21,954,803
Weighted average number of shares outstanding, diluted
22,159,532
22,155,292
22,170,223
22,000,881
Accumulated
Other
Total
Common Shares Issued
Treasury Shares
Additional
Comprehensive
Shareholders'
Shares
Amount
paid-in Capital
Income (Loss)
Deficit
Equity
Balance at January 1, 2025
22,008,766
Net income
4,016,034
Dividends paid
(1,375,612)
Stock-based compensation expense
385,838
Other comprehensive loss
(50,116)
Balance at March 31, 2025
12,504,745
9,983,151
(38,864,654)
99,704,273
1,551,461
(1,375,760)
Vesting of shares of restricted stock
8,639
(75,496)
Balance at June 30, 2025
22,017,405
12,890,583
9,907,655
(38,688,953)
100,190,316
(1,378,515)
41,169
Balance at September 30, 2025
22,058,574
Balance at January 1, 2024
22,222,722
118,272,565
(70,874)
(360,326)
10,874,491
9,772,277
(37,946,042)
100,612,965
1,506,896
(1,370,409)
321,569
Buyback of common shares
(248,700)
(1,203,708)
Retirement of treasury shares
(319,574)
(1,564,034)
319,574
1,564,034
10,054
(4,245)
Balance at March 31, 2024
21,913,202
116,708,531
11,196,060
9,768,032
(37,809,555)
99,863,068
815,660
(1,371,940)
313,589
8,648
Other comprehensive income
25,240
Balance at June 30, 2024
21,921,850
11,509,649
9,793,272
(38,365,835)
99,645,617
(1,374,428)
(125,000)
(627,500)
51,837
Balance at September 30, 2024
21,973,687
11,818,758
9,833,117
(39,374,242)
98,358,664
8
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion of discount on available for sale securities
(297,637)
Gain on derivative contracts
(2,076,000)
(245,095)
Settlement received on derivative contracts
699,265
1,245,931
Settlement of asset retirement obligation
(1,600)
(88,992)
Deferred income tax (benefit) expense
(676,523)
584,088
Changes in assets and liabilities:
1,328,523
1,545,431
(67,878)
Other assets and liabilities
(191,487)
(94,360)
Accounts payable, royalties payable, gathering fees payable, and other accrued liabilities
(430,885)
(1,520,707)
2,532,686
Net cash provided by operating activities
20,896,700
11,821,266
Cash flows from investing activities:
Additions to unproved oil and gas properties
(5,032,558)
(3,100,294)
Additions to proved oil and gas properties
(5,901,411)
(28,728,498)
Additions to gathering system properties
(384,124)
(76,625)
Additions to land, buildings and property and equipment
(12,102)
(13,912)
Purchases of short term investments - available for sale
(4,045,785)
Proceeds from short term investments - held to maturity
23,116,930
978,044
1,813,808
Net cash used in investing activities
(10,352,151)
(11,034,376)
Cash flows from financing activities:
(1,831,208)
(4,129,887)
(4,116,777)
Net cash used in financing activities
(5,947,985)
Effect of currency rates on cash, cash equivalents, and restricted cash
Increase (decrease) in cash, cash equivalents, and restricted cash
6,246,374
(5,098,657)
Cash, cash equivalents, and restricted cash, beginning of period
6,989,793
13,873,628
Cash, cash equivalents, and restricted cash, end of period
13,236,167
8,774,971
Supplemental cash flow disclosures:
Income tax paid - federal
1,417,860
Income tax paid - state (PA)
755,138
Income tax paid - state (other)
26,710
4,000
Interest paid
9,935
16,832
Non-cash investing activities:
Change in proved properties accrued in accounts payable
2,266,859
818,504
Change in gathering system accrued in accounts payable
39,805
173,193
Asset retirement obligation asset additions and adjustments
25,196
39,597
Epsilon Energy Ltd.
1. Description of Business
Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on March 14, 2005, pursuant to the Alberta Business Corporations Act. On February 14, 2019, Epsilon’s registration statement on Form 10 was declared effective by the United States Securities and Exchange Commission and on February 19, 2019, we began trading in the United States on the NASDAQ Global Market under the trading symbol “EPSN.” Epsilon is a North American on-shore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves.
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.
2. Basis of Preparation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the SEC. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. All adjustments which are, in the opinion of management, necessary for a fair statement of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s consolidated financial statements as of and for the year ended December 31, 2024. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.
The Company’s unaudited condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, Epsilon Energy USA, Inc. and its wholly owned subsidiaries, Epsilon Midstream, LLC, Dewey Energy GP, LLC, Dewey Energy Holdings, LLC, Epsilon Operating, LLC, and Altolisa Holdings, LLC. With regard to the gathering system, in which Epsilon owns an undivided interest in the asset, proportionate consolidation accounting is used. All inter-company transactions have been eliminated.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas and oil reserves and related cash flow estimates used in impairment tests of natural gas and oil, and gathering system properties, asset retirement obligations, accrued natural gas and oil revenues and operating expenses, accrued gathering system revenues and operating expenses, as well as the valuation of commodity derivative instruments. Actual results could differ from those estimates.
Reclassification
The consolidated financial statements for the prior periods include certain reclassifications that were made to conform to the current period presentation. Such reclassifications have no impact on previously reported consolidated financial position, results of operations or cash flows.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires public entities, on an annual basis, to disclose disaggregated information about a reporting entity’s effective tax rate reconciliation, using both percentages and reporting currency amounts for specific standardized categories, as well as disclosure of income taxes paid disaggregated by jurisdiction. The amendments will be effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is evaluating the impact of this new standard and believes that the adoption will result in additional disclosures, but will not have any other impact on its consolidated financial statements.
In March 2024, the FASB issued ASU No. 2024-01, Compensation – Stock Compensation (Topic 718): Scope Applications of Profits Interest and Similar Awards (“ASU 2024-01”). The amendments in ASU 2024-01 improve its overall clarity and operability without changing the guidance and adding illustrative examples to determine whether profits interest award should be accounted for in accordance with Topic 718. The Company has adopted ASU No. 2024-01 as of January 1, 2025. There was no impact as a result of the adoption of this ASU.
In November 2024, the FASB issued ASU 2024-3 "Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures." The ASU will improve the decision usefulness for investors by requiring public business entities to disclose more detailed information about their expenses such as (a) inventory and manufacturing expense, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, etc. The amendments will be effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. The amendments will be applied prospectively with an option for a retrospective application. The Company is evaluating the impact of this new standard and believes that the adoption will result in additional disclosures, but will not have any other impact on its consolidated financial statements.
In July 2025, the FASB issued ASU 2025-05, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit losses for Accounts Receivable and Contract Assets. The amendments in this update provide (1) all entities with a practical expedient to assume that current conditions as of the balance sheet date do not change for the remaining life of the assets and (2) entities other than public business entities with an accounting policy election to consider collection activity after the balance sheet date when estimating expected credit losses for current accounts receivable and current contract assets arising from transactions accounted for under Topic 606. The amendments will be effective for fiscal years beginning after December 15, 2025, with early adoption permitted. The Company is evaluating the impact of this new standard and believes that the adoption may result in additional disclosures, but will not have any material impact on its consolidated financial statements.
3. Cash, Cash Equivalents, and Restricted Cash
Cash and cash equivalents include cash on hand and short term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Restricted cash consists of amounts deposited to back bonds or letters of credit for potential well liabilities. The Company presents restricted cash with cash and cash equivalents in the Consolidated Statements of Cash Flows.
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported in the Consolidated Balance Sheets to the total of the amounts in the Consolidated Statements of Cash Flows as of September 30, 2025 and December 31, 2024:
Restricted cash included in other assets
Cash, cash equivalents, and restricted cash in the statement of cash flows
4. Short Term Investments
Short term investments are highly liquid investments with original maturities between three and twelve months. The Company’s short term investments consist of US Treasury Bills. These investments are classified as available-for-sale. Available-for-sale short term investments are reported at fair value in the Consolidated Balance Sheets. Unrealized gains and losses are excluded from earnings and are reported in Accumulated other comprehensive income in the Consolidated Statements of Operations and Comprehensive Income.
As of September 30, 2025 and December 31, 2024, the Company had no short term investments.
During the nine months ended September 30, 2024, the Company sold securities with a carrying amount of $14,989,595 for total proceeds of $15,336,930. The realized gains on these sales were $347,335. An additional $7,780,000 of securities reached maturity with total realized gains of $234,248. During the three months ended September 30, 2024, the Company did not acquire or sell any securities. The realized gains are included in other income in the consolidated Statements of Operations and Comprehensive Income.
5. Property and Equipment
The following table summarizes the Company’s property and equipment as of September 30, 2025 and December 31, 2024:
Asset Acquisitions
During the nine months ended September 30, 2025, Epsilon had no asset acquisitions.
During the nine months ended September 30, 2024, Epsilon acquired assets that included the following:
Management determined that substantially all the fair value of the assets acquired was concentrated in a group of similar identifiable assets. Based on this determination, the acquisition was accounted for as an asset acquisition.
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 published NYMEX forward prices, basis differentials, 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, 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.
During the nine months ended September 30, 2025, Epsilon 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. During the three months ended September 30, 2025, no impairment was recorded.
During the three and nine months ended September 30, 2024, no impairment was recorded. For the year ended December 31, 2024, the Company had $0.53 million of impairment reflected in proved properties on the Consolidated Balance Sheets. To be consistent with the current presentation, the prior year impairment has been reclassed to accumulated depletion, depreciation, amortization and impairment on the Consolidated Balance Sheets.
6. Revolving Line of Credit
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:
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.
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).
We were in compliance with the financial covenants of the agreement as of September 30, 2025.
Balance at
Current
Borrowing Base
Interest Rate
Revolving line of credit
45,000,000
SOFR + 3.25%
7. Shareholders’ Equity
(a)Authorized shares
The Company is authorized to issue an unlimited number of Common Shares with no par value and an unlimited number of Preferred Shares with no par value.
(b)Purchases of Equity Shares
Normal Course Issuer Bid
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.
(c)Equity Incentive Plan
The Board adopted the 2020 Equity Incentive Plan (the “2020 Plan”) on July 22, 2020 subject to approval by Epsilon’s shareholders at Epsilon’s 2020 Annual General and Special Meeting of shareholders, which occurred on September 1, 2020 (the “Meeting”). Shareholders approved the 2020 Plan at the Meeting.
The 2020 Plan provides for incentive compensation in the form of stock options, stock appreciation rights, restricted stock and stock units, performance shares and units, other stock-based awards and cash-based awards. Under the 2020 Plan, Epsilon is authorized to issue up to 2,000,000 Common Shares.
Restricted Stock
For the nine months ended September 30, 2025, no restricted common shares were awarded to the Company’s board of directors and employees. For the year ended December 31, 2024, 300,052 restricted common shares with a weighted average grant date fair value of $5.97 were awarded to the Company’s management, employees, and board of directors. These shares vest over a three-year period, with an equal number of shares being issued per period on the anniversary of the award resolution. The vesting of the shares is contingent on the individuals’ continued employment or service. The Company determined the fair value of the granted Restricted Stock based on the market price of the common shares of the Company on the date of grant.
The following table summarizes restricted stock activity for the nine months ended September 30, 2025, and the year ended December 31, 2024:
Nine months ended
Year ended
September 30, 2025
December 31, 2024
Number of
Weighted
Restricted
Average
Remaining Life
Grant Date
Outstanding
(years)
Fair Value
Balance non-vested Restricted Stock at beginning of period
560,970
1.61
5.77
491,536
1.74
5.59
Granted
-
300,052
1.92
5.97
Vested
(49,808)
5.72
(230,618)
5.65
Balance non-vested Restricted Stock at end of period
511,162
0.95
5.78
Stock compensation expense for the granted Restricted Stock is recognized over the vesting period. Stock compensation expense recognized during the three and nine months ended September 30, 2025 was $376,613 and $1,148,289, respectively (for the three and nine months ended September 30, 2024 was $309,109 and $944,267, respectively).
As of September 30, 2025, the Company had unrecognized stock-based compensation related to these shares of $2,050,180 to be recognized over a weighted average period of 1 year (at December 31, 2024: $3,198,469 over 1.30 years).
(d)Dividends
On February 26, 2025, June 3, 2025, and September 2, 2025, the Board declared a quarterly dividend of $0.0625 per common share (annualized $0.25 per common share) totaling in aggregate an amount of approximately $4.1 million that has been paid during the nine months ended September 30, 2025.
8. Revenue Recognition
Revenues are comprised of sales of natural gas, oil and natural gas liquids (“NGLs”), along with the revenue generated from the Company’s ownership interest in the gas gathering system in the Auburn field in Northeastern Pennsylvania.
Overall, product sales revenue generally is recorded in the month when contractual delivery obligations are satisfied, which occurs when control is transferred to the Company’s customers at delivery points based on contractual terms and conditions. In addition, gathering and compression revenue generally is recorded in the month when contractual service obligations are satisfied, which occurs as control of those services is transferred to the Company’s customers. Gathering System revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $0.4 million and $1.5 million, respectively, for the three and nine months ended September 30, 2025 ($0.3 million and $0.8 million, respectively, for the three and nine months ended September 30, 2024).
The following table details revenue for the three and nine months ended September 30, 2025 and 2024.
Nine Months Ended September 30,
Operating revenue
Natural gas
4,758,578
1,903,946
22,282,495
6,828,155
Natural gas liquids
267,019
335,271
799,289
1,096,678
Oil and condensate
2,510,651
3,964,736
8,504,982
10,193,535
Gathering and compression fees (1)
Total operating revenue
Product Sales Revenue
The Company enters into contracts with third party purchasers to sell its natural gas, oil, NGLs and condensate production. Under these product sales arrangements, the sale of each unit of product represents a distinct performance obligation. Product sales revenue is recognized at the point in time that control of the product transfers to the purchaser based on contractual terms which reflect prevailing commodity market prices. To the extent that marketing costs are incurred by the Company prior to the transfer of control of the product, those costs are included in lease operating expenses on the Company’s Consolidated Statements of Operations and Comprehensive Income.
Settlement statements for product sales, and the related cash consideration, are generally received from the purchaser within 30 days. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the natural gas, oil, NGLs, or condensate. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying Consolidated Balance Sheets until payment is received.
Gas Gathering and Compression Revenue
The Company also provides natural gas gathering and compression services through its ownership interest in the Auburn gas gathering system in Pennsylvania. For the provision of gas gathering and compression services, the Company collects its share of the gathering and compression fees per unit of gas serviced and recognizes gathering revenue over time using an output method based on units of gas gathered.
The settlement statement from the operator of the Auburn GGS is received two months after transmission and compression has occurred. As a result, the Company must estimate the amount of production that was transmitted and compressed within the system. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying Consolidated Balance Sheets until payment is received.
Current Expected Credit Losses
Under ASU 326, Financial Instruments – Credit Losses, estimated losses on financial assets are provided through an allowance for credit losses. The majority of our financial assets are held in cash and cash equivalents and accounts receivable. The accounts receivable are primarily from purchasers of oil and natural gas, counterparties to our financial instruments, and revenues earned for compression and gathering services. Our oil, gas, and natural gas liquids accounts receivable are generally collected within 30 days after the end of the month. Compression and gathering receivables are generally collected within 60 days after the end of the month. We assess collectability through various procedures, including review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts. As of September 30, 2025 and December 31, 2024, we determined that our allowance for credit loss was nil.
2023
Natural gas and oil sales
3,224,441
4,888,294
4,327,886
Joint interest billing
17,476
Gathering and compression fees
1,071,634
918,471
1,543,239
Commodity contract
219,124
36,957
72,075
Interest
54,772
Total accounts receivable
6,015,448
16
9. Accumulated Other Comprehensive Income
Accumulated other comprehensive income includes certain transactions that have generally been reported in the Consolidated Statements of Changes in Shareholders’ Equity. The activity in accumulated other comprehensive income during the three and nine months ended September 30, 2025 and 2024 consisted of the following:
Balance at beginning of period
Translation (loss)/gain
Unrealized gain/(loss) on securities
Balance at end of period
10. Income Taxes
Income tax provisions for the three and nine months ended September 30, 2025 and 2024 are as follows:
Current:
Federal
387,475
(198,619)
3,746,118
268,691
State
85,869
(71,807)
1,014,783
28,685
Total current income tax expense
473,344
(270,426)
4,760,901
297,376
Deferred:
98,977
565,137
(605,049)
919,522
4,176
73,687
(71,474)
(335,434)
Total deferred tax expense
103,153
638,824
The Company files federal income tax returns in the United States and Canada, and various returns in state and local jurisdictions.
The Company believes it has appropriate support for the income tax positions taken and to be taken on our tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of various factors including past experience and interpretations of tax law applied to the facts of each matter. The Company's tax returns are open to audit under the statute of limitations for the years ending December 31, 2021 through December 31, 2024. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.
Starting in 2023, distributions of Epsilon Energy USA Inc. earnings to Epsilon Energy Ltd. incur a 5% U.S. dividend withholding tax, provided the Company is eligible for benefits under the U.S. / Canada income treaty.
Our effective tax rate will typically differ from the statutory federal rate primarily as a result of state income taxes and the valuation allowance against the Canadian net operating loss. The effective tax rate for the nine months ended September 30, 2025 was higher than the statutory federal rate as a result of state income taxes and the valuation allowance against the Canadian net operating loss.
In July 2025, the One Big Beautiful Bill Act (“OBBBA”) was enacted, which includes a broad range of tax reform provisions affecting businesses. The OBBBA extends or makes permanent certain tax law changes enacted as part of the 2017 Tax Cuts and Jobs Act, as well as makes other changes to the current tax code. As a result of this enactment, our deferred tax balances as of September 30, 2025 reflect the provisions of the new law currently in effect, resulting in the deferral of a portion of current federal tax over future periods. As our income tax provision includes both current and deferred components, the overall net impact is not significant. We are continuing to monitor additional provisions of the OBBBA that become effective through 2027 for potential future impact.
11. Commitments and Contingencies
The Company enters into commitments for capital expenditures in advance of the expenditures being made. As of September 30, 2025, the Company had commitments of $0.2 million for capital expenditures.
From time to time, the Company may be involved in various legal matters. Management believes that as of September 30, 2025, there are no legal matters whose resolution could have a material adverse effect on the unaudited condensed consolidated financial statements.
12. Leases
Under ASC 842, Leases, the Company recognized an operating lease related to its corporate office as of September 30, 2025 and December 31, 2024 as summarized in the following table:
Asset
Total operating lease right-of-use assets
Liabilities
Total operating lease liabilities
387,062
476,911
Operating lease costs
185,368
236,044
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases
224,377
214,230
Weighted average remaining lease term (years) - operating lease
2.15
2.50
Weighted average discount rate (annualized) - operating lease
8.25%
On March 1, 2023, the Company commenced a new office lease with a 70 month lease term and future lease payments estimated to be approximately $0.85 million. There are no other pending leases, and no lease arrangements in which the Company is the lessor.
Lease expense for operating leases was $0.19 million and $0.24 million for the nine months ended September 30, 2025 and the year ended December 31, 2024, respectively. This lease expense is presented in other general and administrative expenses in the Consolidated Statements of Operations and Comprehensive Income.
Future minimum lease payments as of September 30, 2025 are as follows:
Operating Leases
43,388
2026
177,021
2027
180,492
2028
183,963
Total minimum lease payments
584,864
Less: imputed interest
(197,802)
Present value of future minimum lease payments
Less: current obligations under leases
(120,799)
Long-term lease obligations
13. Net Income Per Share
Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities.
The net income used in the calculation of basic and diluted net income per share is as follows:
In calculating the net income per share, basic and diluted, the following weighted-average shares were used:
Basic weighted-average number of shares outstanding
Unvested time-based restricted shares
142,222
206,773
141,975
46,078
Diluted weighted-average shares outstanding
The Company excluded the following shares from the diluted EPS because their inclusion would have been anti-dilutive.
Anti-dilutive unvested time-based restricted shares
369,387
408,816
399,441
478,005
14. Operating Segments
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker (CODM). The CODM, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as executive management consisting of the Chief Executive Officer, Chief Financial Officer, and Chief Operating Officer. The CODM uses the Company’s consolidated financial results, including operating income or loss by segment, to make key operating decisions, assess performance, and to allocate resources. Segment performance is evaluated based on operating income or loss as shown in the table below. Interest income and income taxes are managed separately on a group basis.
The Company’s two reportable segments are as follows:
Segment activity for the nine months ended September 30, 2025 and 2024 is as follows:
Upstream
Gas Gathering
As of and for the nine months ended September 30, 2025
Intersegment gathering and compression fees
1,465,548
6,648,114
38,234,880
Reconciliation of operating revenue
Elimination of intersegment revenues
(1,465,548)
Total consolidated operating revenue(1)
Operating costs
Gathering, transportation, and compression
5,705,765
Other lease operating expense
1,909,970
Intersegment other lease operating expense
Impairment
Depletion, depreciation, amortization and accretion
8,419,766
828,207
Segment operating income
11,409,048
4,089,919
14,033,419
Reconciliation of segment operating income
Salary expense
2,622,769
Stock based compensation
Other general and administrative
3,125,312
Elimination of intersegment other lease operating expenses
Total consolidated operating income
Other income (expense)
Other expense
Other expense, net
Capital expenditures (2)
10,946,071
384,124
11,330,195
Segment assets
99,286,044
105,554,519
Total segment assets reconciled to consolidated amounts are as follows:
Total segment assets
Current assets, net
Other property and equipment
859,665
Operating lease right-of-use asset
20
As of and for the nine months ended September 30, 2024
842,625
5,306,759
23,425,127
(842,625)
3,759,752
1,758,078
6,446,271
681,370
5,311,642
2,932,527
7,401,544
2,169,379
2,317,435
31,842,704
76,625
31,919,329
98,473,841
6,766,726
105,240,567
14,811,129
906,897
368,564
121,797,157
21
Segment activity for the three months ended September 30, 2025 and 2024 is as follows:
As of and for the three months ended September 30, 2025
401,325
1,846,536
9,382,784
(401,325)
1,727,590
669,462
2,354,222
216,240
2,383,649
1,066,754
3,049,078
832,977
1,634,808
(196,673)
155,797
(40,876)
22
As of and for the three months ended September 30, 2024
250,718
1,334,706
7,538,659
(250,718)
1,157,373
942,128
2,435,309
263,503
1,418,425
580,878
1,748,585
29,171
1,420,405
2,410,620
6,389
2,417,009
15. Commodity Risk Management Activities
Epsilon engages in price risk management activities from time to time. These activities are intended to manage Epsilon’s exposure to fluctuations in commodity prices for natural gas and oil by securing derivative contracts for a portion of expected sales volumes.
Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor do its counterparties currently require collateral from the Company.
The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future natural gas and oil production and related cash flows. The natural gas and oil revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future natural gas and oil sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.
Epsilon has historically elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Loss on derivative contracts on the condensed Consolidated Statements of Operations and Comprehensive Income. The related cash flow impact is reflected in cash flows from operating activities. During the three and nine months ended September 30, 2025, Epsilon recognized gains on commodity derivative contracts of $964,307 and $2,076,000, respectively. These amounts included cash received of $807,648 and $699,265, respectively. For the three and nine months ended September 30, 2024, Epsilon recognized gains on commodity derivative contracts of $440,712 and $245,095, respectively. These amounts included cash received on settlements on these contracts of $485,389 and $1,245,931, respectively.
At September 30, 2025, the Company had outstanding natural gas NYMEX Henry Hub (“HH”) swaps totaling 1.1 Bcf, natural gas NYMEX HH options totaling 2.19 Bcf, and crude oil NYMEX WTI CMA swaps totaling 30.8 MBbls.
Fair Value of Derivative Assets
Henry Hub Nymex Swap
595,521
151,274
Tennessee Z4 Basis swap
195,211
Henry Hub Nymex Option - Put
382,243
Crude Oil NYMEX WTI CMA
155,529
56,547
Long-term
16,244
313,137
1,462,674
403,032
Fair Value of Derivative Liabilities
(448,852)
(441,728)
Henry Hub Nymex Option - Call
(204,511)
(368,976)
(573,487)
(890,580)
Net Fair Value of Derivatives
(487,548)
Net Current
928,782
Net Long-term
(39,595)
The following table presents the changes in the fair value of Epsilon’s commodity derivatives for the periods indicated:
Fair value of asset (liability), beginning of the period
732,528
144,096
1,100,255
Gain on derivative contracts included in earnings
Settlement of commodity derivative contracts
(807,648)
(485,389)
(699,265)
(1,245,931)
Fair value of asset, end of the period
99,419
16. Asset Retirement Obligations
Asset retirement obligations are estimated by management based on Epsilon’s net ownership interest in all wells and the gathering system, estimated costs to reclaim and abandon such assets and the estimated timing of the costs to be incurred in future periods, and the forecast risk free cost of capital. Each year we review, and to the extent necessary, revise our asset retirement obligations estimates in accordance with recent activity and current service costs.
The following tables summarize the changes in asset retirement obligations for the periods indicated:
Nine Months Ended
Balance beginning of period
3,502,952
Liabilities acquired
48,207
Wells plugged and abandoned
Change in estimates
6,695
Accretion
146,138
183,434
Balance end of period
17. Fair Value Measurements
The methodologies used to determine the fair value of our financial assets and liabilities at September 30, 2025 were the same as those used at December 31, 2024.
Cash and cash equivalents, restricted cash, accounts receivable, and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates. The revolving line of credit is classified within Level 2 of the fair value hierarchy.
Commodity derivative instruments consist of NYMEX HH swap, NYMEX HH option, and Tennessee Z4 basis swap contracts for natural gas, and NYMEX WTI CMA swap contracts for crude oil. The Company’s derivative contracts are valued based on a marked to market approach. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
Level 1
Level 2
Level 3
Effect of Netting
Net Fair Value
Assets
Derivative contracts
Cash equivalents
262,894
573,487
(403,032)
298,767
890,580
Non-Recurring Fair Value Measurements
The Company performed an impairment test on our oil and gas properties and it was determined that the carrying amount of the Canada asset exceeded the estimated undiscounted future cash flows resulting in a reduction of the carrying amount of the properties to their estimated fair values by $2.7 million during the nine months ended September 30, 2025. This nonrecurring fair value measurement is classified within Level 3 of the fair value hierarchy. For the year ended December 31, 2024, there was an impairment of $1.45 million.
The table below summarizes the fair value of the impaired assets at June 30, 2025, the measurement date for the impairment.
Quoted Prices
Significant
in Active
Markets for
Observable
Unobservable
June 30,
Identical Assets
Inputs
(Level 1)
(Level 2)
(Level 3)
Nonrecurring fair value measurement
Long-lived assets held and used (1)
1,342,942
Total Nonrecurring fair value measurement
The table below summarized the fair value of the impaired assets at December 31, 2024.
Long-lived assets held and used
492,253
26
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.”
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.”
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).
Three and nine months ended September 30, 2025 Highlights
Marcellus Shale – Pennsylvania
Permian Basin – Texas and New Mexico
Anadarko, NW Stack Trend – Oklahoma
Western Canadian Sedimentary Basin—Alberta, Canada
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.
Add Back:
Interest income, net
(73,228)
(43,095)
(73,657)
(400,791)
Depreciation, depletion, amortization, and accretion
(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
30
Results of Operations
For the nine months ended September 30, 2025 revenues increased $14.2 million, or 63%, to $36.8 million from $22.6 million during the same period of 2024.
Revenue and volume statistics for the three and nine months ended September 30, 2025 and 2024 were as follows:
Three months ended
Revenues
Pennsylvania
Natural gas revenue
4,591,423
1,833,371
21,621,448
6,435,027
Volume (MMcf)
2,045
1,190
7,336
4,032
Avg. Price ($/Mcf)
2.24
1.54
2.95
1.60
Gathering system revenue (net of elimination)
Total PA Revenues
6,036,634
2,917,359
26,804,014
10,899,161
Permian Basin
39,312
(27,499)
134,840
11,322
57
108
158
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
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
117,000
98,074
490,975
381,806
45
150
188
2.61
1.72
3.28
2.04
70,337
96,009
252,415
315,732
3.4
4.1
10.8
13.4
20.49
23.60
23.33
23.55
100,271
207,162
391,654
682,755
1.6
2.7
5.8
8.7
64.61
77.33
67.31
78.06
Total OK Revenues
287,608
401,245
1,135,044
1,380,293
Canada
10,843
35,232
0.60
1.01
29,550
52,944
1.4
2.3
21.76
23.05
217,188
737,160
3.8
56.89
56.24
Total Canada Revenues
257,581
825,336
Total Revenues
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.
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:
Lease operating costs (net of elimination)
Gathering system operating costs
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”)
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.
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”)
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 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.
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.
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.
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.
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 $45 million (redetermined as of February 10, 2025), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of June 28, 2027. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower). There are currently no borrowings under the facility.
Additionally, if the Leverage ratio is greater than 1.0 to 1.0, or the borrowing base utilization is greater than 50%, the Company is required to hedge 50% of the anticipated production from PDP reserves for a rolling 24 month period.
The Company has entered into hedging arrangements to reduce the impact of commodity price volatility on operations. By reducing the price volatility from a portion of natural gas and crude oil production, the potential effects of changing prices on operating cash flows have been partially mitigated, but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices.
At September 30, 2025, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:
Weighted Average Price ($/Mmbtu)
Volume
Ceiling
Floor
Basis
Fair Value of Asset
Derivative Type
(MMbtu)
Swaps
Price
Differential
183,000
4.66
193,937
262,000
3.47
74,393
(9,659)
912,000
4.27
417,827
1,345,300
3.80
411,163
4.86
(338,906)
579,400
3.30
209,824
5.40
(224,921)
3,281,700
733,658
Weighted Average
(Bbl)
Price ($/Bbl)
21,800
67.66
125,226
9,000
67.12
30,303
30,800
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.
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.
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.
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.
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.
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.
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.
None.
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.
(c) Purchases of Equity Securities by Epsilon Energy Ltd.
For the nine months ended September 30, 2025, no shares had been repurchased.
Not applicable.
ITEM 6. —EXHIBITS
Exhibit
No.
Description of Exhibit
31.1
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS
Inline XBRL Instance Document.
101.SCH
Inline XBRL Schema Document.
101.CAL
Inline XBRL Calculation Linkbase Document.
101.DEF
Inline XBRL Definition Linkbase Document.
101.LAB
Inline XBRL Labels Linkbase Document.
101.PRE
Inline XBRL Presentation Linkbase Document.
104
Cover Page Interactive Data File (embedded within the Inline XBRL document)
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
(Registrant)
Date: November 5, 2025
By:
/s/ J. Andrew Williamson
J. Andrew Williamson
Chief Financial Officer