Epsilon Energy Ltd. (EPSN) FY 2022 MD&A

ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion is intended to assist in the understanding of trends and significant changes in or results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented. This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2022 and 2021 and for the years then ended together with accompanying notes.

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 area of operation is Pennsylvania.

At December 31, 2022 our total estimated net proved reserves were 90,040 MMcf of natural gas reserves, 491,226 Bbls of NGL reserves, and 211,059 Bbls of oil and other liquids, and we held leasehold rights to approximately 75,954 gross (13,625 net) acres. We have natural gas production in Pennsylvania, and natural gas, oil and other liquid production from our operated and non-operated wells in Oklahoma.

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

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To date, our investments have been focused on the Marcellus Shale unconventional reservoir in Pennsylvania (“PA”). Our PA assets are supported by our 35% ownership in the Auburn GGS. Over the last two years, we have also been active in our position in the NW Stack area of Oklahoma (“OK”). We have a substantial remaining drillable location inventory within our existing leasehold in PA and OK.

The Company also seeks to identify new opportunities in onshore North American natural gas and oil basins. In the second half of 2022, we evaluated several potential investments outside our existing projects, with a focus on the Northeastern United States. We expect to expand our area of interest in 2023 to selectively consider potential investments in other North American gas and oil basins.

During 2022, we realized net income of $35.4 million as compared to net income of $11.6 million for 2021.

At December 31, 2022, our total estimated net proved developed reserves were 80,795 MMcfe, an increase of 10% from December 31, 2021. The increase is mainly attributable to revisions to previous estimates and transfers from proved undeveloped.

At December 31, 2022, our total estimated net proved reserves were 94,254 MMcfe, a 20% decrease from December 31, 2021. The decrease in our total proved reserves is due to a change in our previously adopted development plan, primarily attributable to estimated proved undeveloped reserves in PA and OK that shifted into the probable reserve category under SEC guidelines due to timing. As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator. We anticipate reevaluating these reserves once we have line of sight on development timing.

Our standardized measure of discounted future net cash flows as of December 31, 2022 and 2021 was $145.8 million and $77.7 million, respectively. This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets.

Results of Operations

The following review of operations for the periods presented below should be read in conjunction with our consolidated financial statements and the notes thereto.

Revenues

During the year ended December 31, 2022, revenues increased $27.6 million, or 65%, to $70.0 million from $42.4 million during the year ended December 31, 2021 due primarily to increased prices.

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Revenue and volume statistics for the years ended December 31, 2022 and 2021 were as follows:

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Upstream natural gas revenue for the year ended December 31, 2022 increased by $25.2 million, or 80%, over 2021. An increase of $27.5 million was due to higher natural gas prices partially offset by a reduction of $2.3 million due to lower volumes being produced due to natural decline of the wells.

Upstream natural gas liquids revenue for the year ended December 31, 2022 increased by $0.7 million, or 65% over 2021.  This was a result of increased production from new wells in addition to higher NGL prices.

Upstream oil and other liquids revenue for the year ended December 31, 2022 increased by $1.4 million, or 80% over 2021.  This was a result of increased production from new wells in addition to higher oil prices.

Gathering system revenue for the year ended December 31, 2022 increased by $0.2 million, or 3% over 2021. This was the result of increased throughput in the system. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $1.5 million and $1.6 million, respectively, for the years ended December 31, 2022 and 2021.,

Operating Costs

The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the years ended December 31, 2022 and 2021:

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Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system. Prior to the year ended December 31, 2022, the gathering fees were netted from the gathering system operating costs.  For the year ended December 31, 2022, the Company determined that it would be more appropriate to net the $1.5 million fees from the upstream lease operating costs.  To be consistent with the current presentation, the prior year elimination of $1.6 million has been reclassed as well.

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 year ended December 31, 2022, upstream operating costs increased by $0.8 million, or 13.1% from the same period in 2021. The increase was due to extraordinary plugging and abandonment costs related to atypical wellbore conditions in two older vintage wells in Pennsylvania, which is not representative of the other wells.

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 year ended December 31, 2022, gathering system operating costs decreased by $0.03 million, or 1.4% from the same period in 2021.

Depletion, Depreciation, Amortization and Accretion (DD&A)

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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. At this time, the Company has only minimal leasehold acquisition costs. For natural gas and oil development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves. A reserve report is prepared as of December 31, each year.

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.

During the year ended December 31, 2022, DD&A expense was generally consistent compared to the same period in 2021, decreasing by $0.2 million, or 3%.

Impairment

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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, 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 values 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.

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For the year ended December 31, 2022, no impairment was recorded. For the year ended December 31, 2021, the Company recognized dry hole costs of $0.15 million.

Gain (Loss) on Sale of Properties

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For the year ended December 31, 2022, the Company recorded a gain for a well-bore only asset sale and conveyance and partial release of oil and gas leases in Oklahoma. For the year ended December 31, 2021, the Company recorded a gain on the sale of the shallow rights leases and wells in Oklahoma.

General and Administrative (“G&A”)

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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 stock options granted and restricted shares of stock granted and the related non-cash compensation.

G&A expenses increased by $0.5 million, or 8%, during the year ended December 31, 2022 from 2021. Increased compensation costs of $1.3 million associated with the management transition was offset by a decrease in legal fees by $0.8 million.

Interest Expense

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Interest expense relates to the interest and commitment fees paid on the revolving line of credit.

Interest expense decreased by $0.05 million, or 50%, during the year ended December 31, 2022 from 2021. The decrease is due to the reduction in the borrowing base on our line of credit during this time.

Net gain (loss) on commodity contracts

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During the years ended December 31, 2022 and 2021, we entered into NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, Dominion basis swaps, and two-way costless collar derivative contracts for the purpose of hedging our physical natural gas sales revenue. The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2022, the Company paid net cash settlements of $1,225,837. For the year ended December 31, 2021, the Company paid net cash settlements of $4,243,085.

In April 2022, the Company added NYMEX HH collars totaling 1.2 Bcf and basis swaps totaling 1.2 Bcf. NYMEX HH prices generally increased throughout the first three quarters of 2022 resulting in realized losses for the year ended December 31, 2022.

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In February 2021, the Company added Henry Hub collars totaling 3.96 Bcf and basis swaps totaling 0.31 Bcf. In August 2021, the Company added Henry Hub swaps totaling 0.46 Bcf and basis swaps totaling 1.10 Bcf. NYMEX HH prices generally increased throughout 2021 resulting in large realized losses for the year ended December 31, 2021.

At December 31, 2022, the Company had outstanding NYMEX HH swaps totaling 1.07 Bcf with a trade price of $5.212 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a trade price of ($1.25) to hedge a portion of expected volumes for the contract period of April 2023 to October 2023.

Other Income (Expense)

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During the year ended December 31, 2022, interest income increased by $0.4 million, or 877%, during the year ended December 31, 2022 from the same period in 2021. This increase was primarily due to the utilization of additional financial instruments with higher prevailing interest rates in 2022.

Net Income Compared to Adjusted EBITDA

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We define 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 derivative contracts net of cash received or paid on settlement, and (7) other income. 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. We have included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA provides useful information regarding our 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 us 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 above sets forth a reconciliation of net income to Adjusted EBITDA, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully.

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Capital Resources and Liquidity

Cash Flow

The primary source of cash during the years ended December 31, 2022 and 2021 was funds generated from operations. For the years ended December 31, 2022 and 2021, cash was primarily used for operations, as well as the development of natural gas and oil properties, the buyback of common shares through our share repurchase program, and the pre-payment of income taxes. In 2022, we began paying dividends quarterly, which totaled $5.9 million.

At December 31, 2022, we had a working capital surplus of $51.0 million, an increase of $26.9 million from the $24.1 million surplus at December 31, 2021. The surplus increased from December 31, 2021 primarily due to the increase in realized prices during 2022. We anticipate that our current cash balance, cash flows from operations, and available sources of liquidity to be sufficient to meet our cash requirements.

Year ended December 31, 2022 compared to 2021

During the year ended December 31, 2022, $38.0 million was provided by our operating activities, compared to $20.0 million in 2021, a $18.0 million, or 90%, increase. The increase was mainly due to the increase in realized prices resulting in increased revenue.

We used $7.9 million for investing activities during the year ended December 31, 2022, compared to $4.4 million in 2021, a $3.4 million, or 77%, increase. This was spent primarily on upstream development costs in Pennsylvania and Oklahoma.

During the year ended December 31, 2022, $12.0 million of cash used for financing activity was related to the repurchase of our common shares and the payment of quarterly dividends. This was offset by $0.7 million of proceeds from the exercise of stock options. During the year ended December 31, 2021, $2.3 million of cash was used for financing activity, which was primarily related to the repurchase of our common shares.

Credit Agreement

The Company has a senior secured credit facility which includes a total commitment of up to $100 million. The effective borrowing base is $30 million, which is subject to semi-annual redetermination. There are currently no borrowings under the facility. If we decide to access the facility, depending on the level of borrowing, we might need to increase our hedging activity. Borrowings from the Facility may be used for the acquisition and development of oil and gas properties, investments in cash flow generating assets complimentary to the production of oil and gas, and for letters of credit and other general corporate purposes. Upon each advance, interest is charged at the highest of a) the Prime Rate, or b) the sum of the Federal Funds Rate plus 0.5%, plus an applicable margin (0.25%-1.25%, based on percentage utilization on the facility).

The facility matures on March 1, 2024.

Effective April 6, 2021, the agreement was amended to extend the maturity date to March 1, 2024. In addition, the agreement was amended to include a Benchmark Replacement definition and transition plan to be used at such time when the LIBOR rate is discontinued.

On February 10, 2023, Epsilon Energy USA entered into the Ninth Amendment of the Credit Agreement. The borrowing base was increased to $30 million. LIBOR was removed as a reference option in the calculation of interest. Hedging requirements were amended to be between 0%-62.5% of the 24-month projected production volumes, based on percentage utilization on the facility. Also, cash distributions to the parent company (Epsilon Energy Ltd.) were allowed

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if the facility is 80% utilized and the leverage ratio (total debt / income adjusted for interest, taxes and non-cash amounts) is less than 2.

The bank has a first priority security interest in the tangible and intangible assets of Epsilon Energy USA, Inc. to secure any outstanding amounts under the agreement. Under the terms of the agreement, the Company must maintain the following covenants:

We were in compliance with the financial covenants of the agreement as of December 31, 2022.

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Repurchase Transactions

Commencing on March 8, 2022, we implemented a plan to repurchase our issued and outstanding common shares and to return capital to our shareholders. We used cash on hand to fund these repurchases. During the year ended December 31, 2022, we repurchased 982,500 common shares of the maximum of 1,183,410 authorized for repurchase and spent $6,234,879 under the plan. The repurchased stock had an average price of $6.32 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.

In 2023, we repurchased 190,700 common shares at an average price of $5.82 per share (excluding commissions) before the plan terminated on March 7, 2023.

Commencing on January 1, 2021, we implemented a plan to repurchase our issued and outstanding common shares. The plan terminated on December 31, 2021. We used cash on hand to fund these repurchases. During the year ended December 31, 2021, we repurchased 534,015 common shares of the maximum of 1,193,000 authorized for repurchase and spent $2,423,007 under the plan. The repurchased stock had an average price of $4.51 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.

On March 9, 2023, the Board of Directors authorized a new share repurchase program of up to 2,292,644 common shares, representing 10% of the outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $15.0 million. The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program will commence on March 27, 2023 and end on March 26, 2024, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.

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Derivative Transactions

The Company has entered into hedging arrangements to reduce the impact of natural gas price volatility on operations. By removing the price volatility from a significant portion of natural gas production, the potential effects of changing prices on operating cash flows have been 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 December 31, 2022, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following:

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Contractual Obligations

We enter into commitments for capital expenditures in advance of the expenditures being made. At a given point in time, it is estimated that we have committed to capital expenditures equal to approximately one quarter of our capital budget by means of giving the necessary authorizations to the asset operator to incur the expenditures in a future period. Current commitments amounted to approximately $0.8 million, all of which we expect to incur in 2023.

Based on current natural gas prices and anticipated levels of production, we believe that the estimated net cash generated from operations, together with cash on hand and amounts available under our credit agreement, will be adequate to meet liquidity needs for the next 12 months and beyond, including satisfying our financial obligations and funding our operating and development activities.

Off Balance Sheet Arrangements

As of December 31, 2022 and 2021, we had no off-balance sheet arrangements.

Summary of Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements and accompany notes, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, and SEC rules which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Described below are the most significant accounting policies we apply in preparing our consolidated financial statements. We also describe the most significant estimates and assumptions we make in applying these policies.

Proved Natural Gas and Oil Reserves

Our engineers estimate proved natural gas and oil reserves in accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved natural gas and oil reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward)

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to existing reserve estimates may occur from time to time. We cannot predict the types of reserve revisions that will be required in future periods. For related discussion, see the sections titled “Risk Factors” and “Supplemental Information to Consolidated Financial Statements.”

Unproved Natural Gas and Oil Properties

Unproved properties generally consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of natural gas and oil properties in the consolidated statements of operations and comprehensive income (loss). Unproved natural gas and oil property costs are transferred to proved natural gas and oil properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved natural gas and oil properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors.

Depreciation, Depletion and Amortization of Natural gas and oil Properties and Gathering Systems

The quantities of estimated proved natural gas and oil reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease, respectively.

Oil and natural gas 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, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.

Impairments

The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.

We compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the carrying value of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the carrying value of the asset, the carrying value is reduced to fair value. Fair value is generally calculated using the “Income Approach” based on estimated discounted net cash flows. Estimates of future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate.

We evaluate impairment of proved and unproved natural gas and oil properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. The basis for future depletion, depreciation, amortization, and accretion will take into account the reduction in the value of the asset as a result of any accumulated impairment losses.

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When circumstances indicate that the gathering system properties may be impaired, Epsilon compares expected undiscounted future cash flows related to the gathering system to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach, which considers estimated discounted future cash flows.

Derivative Financial Instruments

Derivative financial instruments are used to hedge exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap and collar contracts. The use of these instruments is subject to policies and procedures as approved by the Board. Derivative financial instruments are not traded for speculative purposes. No derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the consolidated statements of operations and comprehensive income (loss). The estimated fair value of derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values reported in Epsilon’s financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts. We believe credit risk is minimal and do not anticipate such nonperformance by such counterparties.

Asset Retirement Obligations (“ARO”)

We recognize asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. For our upstream properties, these obligations consist of estimated future costs associated with the plugging and abandonment of natural gas and oil wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. For our gathering system, these obligations consist of estimated future costs associated with the removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the natural gas and oil or gathering system asset. The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing of settlements; the credit-adjusted risk-free discount rate; and the inflation rate. In periods subsequent to the initial measurement of an ARO, period-to-period changes are recognized in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the natural gas and oil property or gathering system asset.

Income Taxes

Tax regulations and legislation in the U.S. and Canada are subject to change and differing interpretations requiring judgment. We compute income taxes using the asset-and-liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities, as well as loss and tax credit carryforwards. Changes in tax rates and laws are recognized in income in the period such changes are enacted.

We establish a valuation allowance if, based on available evidence, it is more likely than not that some or all of the deferred tax assets will not be realized. We consider all positive and negative evidence, including historical operating results, the existence of cumulative losses, estimates of future operating income, and the reversal of existing taxable temporary differences in assessing the need for a valuation allowance. Income tax filings are subject to audits and

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re-assessments. Changes in facts, circumstances, and interpretations of the standards may result in a material increase or decrease in our provision for income taxes.

Recently Issued Accounting Standards

See Note 3 Summary of Significant Accounting Policies in Notes to the Consolidated Financial Statements.

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