Epsilon Energy Ltd.: Form 10-Q for the period ended Sep 30, 2024

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, 2024 and 2023 and for the nine months then ended 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, 2023. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward- looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Forward-Looking Statements.”

Overview

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

At September 30, 2024 we held leasehold rights to 23,630 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, 2023 our total estimated net proved reserves were 65,916 MMcf of natural gas, 383,174 Bbls of NGLs, and 341,286 Bbls of oil and condensate.

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

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

Business Strategy

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

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

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

On February 27, 2024, Epsilon acquired a 25% working interest in three producing wells and 3,246 gross undeveloped acres on the Central Basin Platform in Ector County, Texas from a private operator. The assets are immediately offset to the assets acquired in June 2023. The total purchase price was $14.8 million.

In the second and third quarter of 2024, Epsilon participated in the drilling and completion of 2 gross wells in Ector County, Texas. The wells were put on production in June and August 2024.

In April 2024, Epsilon acquired a 50% working interest in 14,243 gross acres for $1.0 million. Epsilon participated in the drilling of 2 gross wells in the third and fourth quarter of 2024.

In October 2024, Epsilon formed a joint venture with a private operator covering lands in the Western Sedimentary Basin in Alberta, Canada. Epsilon will earn a 25% working interest across approximately 160,000 gross acres after fulfilling a carried interest commitment of $7.3 million before December 1, 2025.

We continue to evaluate new opportunities in numerous onshore North American natural gas and oil basins.

Three and nine months ended September 30, 2024 Highlights

Operational Highlights

Marcellus Shale – Pennsylvania

• During the three months ended September 30, 2024, Epsilon's realized natural gas price was $1.54 per Mcf, a 44% increase over the three months ended September 30, 2023. During the nine months ended September 30, 2024, Epsilon's realized natural gas price was $1.60 per Mcf, an 8% decrease over the nine months ended September 30, 2023.
• During the three months ended September 30, 2024, Epsilon’s net revenue interest natural gas production was 1.2 Bcf compared to 1.7 Bcf during the same period in 2023, a 32% decrease. During the nine months ended September 30, 2024, Epsilon’s net revenue interest natural gas production was 4.0 Bcf compared to 6.0 Bcf during the same period in 2023, a 33% decrease.
• Gathered and delivered 7.0 Bcf gross (2.5 net to Epsilon's interest) during the three months ended September 30, 2024, or 76 MMcf/d through the Auburn Gas Gathering System. Gathered and delivered 30.2 Bcf gross (10.6 net to Epsilon's interest) during the nine months ended September 30, 2024, or 111 MMcf/d through the Auburn Gas Gathering System.
• On May 17, 2024, Epsilon Energy USA, Inc. ("Epsilon”) executed a new Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania (the "ASGGA”) with operator Appalachia Midstream Services, LLC for a primary term of ten years and an effective date of January 1, 2024. Epsilon simultaneously terminated the prior agreement. The new ASGGA establishes fixed gathering, compression and cross-flow rates for all shippers on each system into which Epsilon produces natural gas. These rates will be adjusted annually by the Consumer Price Index for All Urban Consumers ("CPI-U”) commencing January 2025. Notably, the gathering rates in Auburn GGS, Rome GGS & Overfield GGS will no longer be subject to a cost-of-service redetermination annually; however, acreage dedications, service priority levels, required shipper approvals and shipper voting procedures are all substantially similar to the prior agreement. The new fixed rate for gathering services in Auburn GGS for 2024 is $0.475 per MMBtu.
• At September 30, 2024, the Company had seven gross (.7 net) drilled and completed wells waiting to be turned in line.

Permian Basin – Texas and New Mexico

• During the three months ended September 30, 2024, Epsilon's realized price for all Permian Basin production was $54.19 per Boe (90% liquids), a 16% increase over the three months ended September 30, 2023. During the nine months ended September 30, 2024, Epsilon's realized price for all Permian Basin production was $53.82 per Boe (86% liquids), a 14% increase over the nine months ended September 30, 2023.
• Total net revenue interest production for the three months ended September 30, 2024, which included oil, natural gas liquids, and natural gas, was 73.3 Mboe compared to 13.9 Mboe during the same period in 2023, a 428% increase. Total net revenue interest production for the nine months ended September 30, 2024, which included oil, natural gas liquids, and natural gas, was 191.4 Mboe compared to 28.8 Mboe during the same period in 2023, a 565% increase.

Anadarko, NW Stack Trend – Oklahoma

• During the three months ended September 30, 2024, Epsilon's realized price for all Oklahoma production was $4.12 per Mcfe (58% natural gas), a 16% decline from the three months ended September 30, 2023. During the nine months ended September 30, 2024, Epsilon's realized price for all Oklahoma production was $4.31 per Mcfe (59% natural gas), a 20% decline from the nine months ended September 30, 2023.
• Total net revenue interest production for the three months ended September 30, 2024 included natural gas, oil and other liquids and was 0.10 Bcfe, a 34% decrease from the same period in 2023. Total net revenue interest production for the nine months ended September 30, 2024 included natural gas, oil and other liquids and was 0.32 Bcfe, a 36% decrease from the same period in 2023.

Non-GAAP Financial Measures-Adjusted EBITDA

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

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

The table below sets forth a reconciliation of net income to Adjusted EBITDA for the three and nine months ended September 30, 2024 and 2023, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully.

Results of Operations

Net Operating Revenues

For the nine months ended September 30, 2024 revenues increased $0.4 million, or 2%, to $22.6 million from $22.2 million during the same period of 2023.

Revenue and volume statistics for the three and nine months ended September 30, 2024 and 2023 were as follows:

Upstream natural gas revenue for the nine months ended September 30, 2024 decreased by $4.5 million, or 40%, over the same period in 2023. A decrease of $1.0 million was due to lower natural gas prices and a decrease of $3.5 million was due to lower sales volumes as a result of natural decline in the wells and operator elected well shut-ins due to poor natural gas pricing in Pennsylvania. Upstream natural gas revenue for the three months ended September 30, 2024 decreased by $0.2 million, or 9%, over the same period in 2023. An increase of $0.4 million was due to higher natural gas prices and a decrease of $0.6 million was due to lower sales volumes as a result of natural decline in the wells and operator elected well shut-ins due to poor natural gas pricing in Pennsylvania.

Upstream natural gas liquids revenue for the nine months ended September 30, 2024 increased by $0.4 million, or 64% over the same period in 2023. An increase of $0.7 million was due to additional sales volumes from new wells drilled and acquired in the Permian Basin and a decrease of $0.3 million was due to lower sales prices. Upstream natural gas liquids revenue for the three months ended September 30, 2024 increased by $0.1 million, or 47% over the same period in 2023. An increase of $0.2 million was due to additional sales volumes from a new well drilled in the Permian Basin and a decrease of $0.1 million was due to lower sales prices.

Upstream oil and condensate revenue for the nine months ended September 30, 2024 increased by $7.7 million, or 310% over the same period in 2023. An increase of $7.5 million was due to additional sales volumes from new wells drilled and acquired in the Permian Basin and an increase of $0.2 million was due to slightly higher prices. Upstream oil and condensate revenue for the three months ended September 30, 2024 increased by $3.0 million, or 329% over the same period in 2023. An increase of $2.9 million was due to additional sales volumes from a new well drilled in the Permian Basin offset and an increase of $0.1 million was due to slightly higher prices.

Gathering system revenue decreased $3.2 million, or 42%, for the nine months ended September 30, 2024 over the same period in 2023. This was primarily the result of lower anchor shipper volumes due to natural decline in the wells and operator elected well shut-ins, offset partially by a 17% increase in the Auburn gathering rate. Gathering system revenue decreased $2.0 million, or 65%, for the three months ended September 30, 2024 over the same period in 2023. This was primarily the result of lower anchor shipper volumes due to natural decline in the wells and operator elected well shut-ins, offset partially by a 17% increase in the Auburn gathering rate. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $0.3 million and $0.8 million, respectively, for the three and nine months ended September 30, 2024, and $0.3 million and $1.0 million, respectively, for the three and nine months ended September 30, 2023.

Operating Costs

The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the three and nine months ended September 30, 2024 and 2023:

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 to ready it for sale. For the nine months ended September 30, 2024 these costs increased by $1.1 million, or 25%, over the same period in 2023. The increase is primarily due to the acquired and developed wells in the Permian Basin during the fourth quarter of 2023 and 2024. For the three months ended September 30, 2024 these costs increased by $0.5 million, or 35%, over the same period in 2023. The increase is primarily due to the acquired and developed wells in the Permian Basin during the fourth quarter of 2023 and 2024.

The higher unit operating costs in the three and nine months ending September 30, 2024 were primarily due to the higher liquids proportion of sales (Mcfe).

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 nine months ended September 30, 2024, gathering system operating costs were constant, decreasing by $0.2 million, or 9% from the same period in 2023. For the three months ended September 30, 2024, gathering system operating costs decreased by $0.1 million, or 22% from the same period in 2023. The decrease related to lower throughput volumes.

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 three and nine months ended September 30, 2024 increased by $1.3 million, or 94%, and $2.3 million, or 49%, respectively, from the same periods in 2023. This increase was a result of the new production in the Permian Basin and a lower reserve base in Pennsylvania used in the calculation, driven by lower SEC realized natural gas prices.

General and Administrative (“G&A”)

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 units granted.

G&A expenses for the three and nine months ended September 30, 2024 and 2023 decreased by $0.2 million, or 11%, and $0.5 million, or 9%, respectively, from the same period in 2023. This was primarily due to lower cash bonus expenses and lower legal fees.

Interest Income

Interest income for the three and nine months ended September 30, 2024 and 2023 decreased by $0.3 million, or 75%, and $0.8 million, or 64%, respectively, from the same period in 2023. This was primarily due to a reduction in the amount of outstanding financial instruments in short term investments.

Interest Expense

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

Interest expense during the nine months ended September 30, 2024 and 2023 was materially unchanged. Interest expense for the three months ended September 30, 2024 and 2023 increased by $0.04 million, or 506%, as a result of a change in the fee structure under the new credit facility.

Gain (Loss) on Derivative Contracts

For the three and nine months ended September 30, 2024, 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. For the three and nine months ended September 30, 2023, Epsilon had NYMEX HH Natural Gas Futures swaps and Tennessee Gas Pipeline Zone 4 basis swap derivative contracts for the purpose of hedging a portion of its physical natural gas sales revenue.

During the three and nine months ended September 30, 2024, we received net cash settlements of $485,389 and $1,245,931, respectively. During the three and nine months ended September 30, 2023, we received net cash settlements of $1,346,270 and $2,979,128, respectively.

For the nine months ended September 30, 2024, net gains on derivative contracts decreased by $1.4 million. This decrease was primarily the result of NYMEX Henry Hub prices not declining as much relative to the strike price of the hedge in 2024 as compared to 2023. For the three months ended September 30, 2024, net gains on derivative contracts increased by $0.5 million. This increase was primarily a result of declining NYMEX Henry Hub and WTI CMA prices in 2024. There were minimal price fluctuations for the same period in 2023.

Capital Resources and Liquidity

Cash Flow

The primary source of cash for Epsilon during the three and nine months ended September 30, 2024 and 2023 was funds generated from operations. The primary uses of cash for the three and nine months ended September 30, 2024 and 2023 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, 2024, we had a working capital surplus of $7.5 million, a decrease of $25.7 million from the $33.2 million surplus at December 31, 2023. The Company anticipates its current cash balance, short term investments, 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, 2024 compared to 2023

During the nine months ended September 30, 2024, $11.8 million was provided by the Company’s operating activities, compared to $14.4 million during the same period in 2023, representing an 18% decrease.

The Company used $11.0 million and $37.1 million of cash for investing activities during the nine months ended September 30, 2024 and 2023, respectively. During the nine months ended September 30, 2024, the Company had net investments of $30.1 million primarily on leasehold and well costs in Pennsylvania, Texas, and Canada offset by net proceeds of $19.1 million in U.S. Treasury Bills. During the nine months ended September 30, 2023, the Company had net investments of $18.3 million in U.S. Treasury Bills and $18.8 million in leasehold and development costs targeting increasing production in Pennsylvania, the Permian Basin, and Oklahoma.

The Company used $5.9 million and $10.1 million of cash for financing activities during the nine months ended September 30, 2024 and 2023, respectively. This was spent on dividend payments and the repurchase of shares of common stock.

Credit Agreement

The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender. The current commitment and borrowing base is $45 million (redetermined on June 25, 2024), supported by the Company’s upstream assets and subject to semi-annual redeterminations with a maturity date of the earlier of June 28, 2027 or the date that the commitments are terminated. 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) and guaranteed by the Company and the other wholly owned subsidiaries. There are currently no borrowings under the facility.

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

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

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

Repurchase Transactions

On March 20, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the outstanding common shares of Epsilon at such time, for an aggregate purchase price of not more than US $12.0 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 March 27, 2024 and will end on March 26, 2025, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.

During the three and nine months ended September 30, 2024, 125,000 shares have been repurchased at a price of $5.00 per share (excluding commissions) under the new program. These shares are currently held in treasury and will be retired during the fourth quarter of 2024.

The previous share repurchase program commenced on March 27, 2023 and ended on March 26, 2024. During the year ended December 31, 2023, we repurchased 968,149 common shares at an average price of $5.08 per share (excluding commissions) under the previous plan. In 2024, we repurchased and retired 248,700 shares at a price of $4.82 per share (excluding commissions) before the plan terminated.

During the nine months ended September 30, 2024, the Company repurchased 373,700 shares at a price of $4.88 per share (excluding commissions) under the two consecutive repurchase programs.

Derivative Transactions

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

At September 30, 2024, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:

Contractual Obligations

The Company enters into commitments for capital expenditures in advance of the expenditures being made. As of September 30, 2024, the Company has no unpaid short term commitments for capital expenditures and has long term commitments of $15.2 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.

Gathering System Revenue Risk

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

Interest Rate Risk

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

At September 30, 2024 and 2023, the outstanding principal balance under the credit agreement was nil.

Derivative Contracts

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

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our chief executive officer and chief financial officer have concluded that our current disclosure controls and procedures were effective as of September 30, 2024 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, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Effectiveness of Controls

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

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, 2023.