What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-03-19 compared with 2024-03-21 · 95 added, 80 removed, 201 unchanged (47% of the section changed)

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(the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves.

Our areas of operations are the Marcellus Shale section of the Appalachian Basin in Pennsylvania, the Permian Basin in Texas and New Mexico, and the NW Anadarko Basin in Oklahoma.

Our 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 December 31, 2024 our total estimated net proved reserves were 69,401 MMcf of natural gas reserves, 876,808 Bbls of NGL reserves, and 1,572,465 Bbls of oil and condensate, and we held leasehold rights to approximately 102,506 gross (23,602 net) acres.

We have natural gas production from our non-operated wells in Pennsylvania, and natural gas, oil and other liquids production from our non-operated wells in the Permian Basin and Oklahoma.

We have natural gas production from our non-operated wells in Pennsylvania;

natural gas, oil and other liquids production from our non-operated wells in the Permian Basin, Oklahoma;

and oil production from our non-operated well in Alberta, Canada.

We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks.

We plan to maintain a strong balance sheet and liquidity position to allow us to opportunistically invest in both our existing project areas and potential new projects.

Historically, our investments have been focused on our position in the prolific Marcellus unconventional reservoir in Pennsylvania (“PA”).

Our PA assets are supported by our 35% ownership in the Auburn GGS.

We have a substantial remaining drillable location inventory within our existing leasehold.

On May 9, 2023, Epsilon acquired a 10% interest in two wellbores located in Eddy County, New Mexico from a private operator.

The wells are currently in production.

Total capital expenditure (net to Epsilon) was $2.2 million.

On May 16, 2023, Epsilon acquired a 25% working interest in 1,297 gross acres on the Central Basin Platform in Ector County, Texas from a private operator.

The Company participated in the drilling and completion of 2 gross (0.5 net) wells which were put on production in October 2023.

Total capital expenditures (net to Epsilon) to date are $9.3 million, including leasehold and drilling and completion costs.

On June 20, 2023, Epsilon acquired a 25% working interest in 11,067 gross acres on the Central Basin Platform in Ector County, Texas from a private operator.

Total leasehold capital expenditures (net to Epsilon) to date are $6.2 million.

Our Pennsylvania (“PA”) assets are supported by our 35% ownership in the Auburn GGS.

We have a substantial remaining drillable location inventory within our existing leaseholds in Pennsylvania and Texas.

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 16,592 gross acres and 7 producing wells in Texas.

Total capital expenditures (net to Epsilon) through year-end 2024 in the project (including undeveloped leasehold) are $38.6 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 year-end 2024 in the project (including undeveloped leasehold) are $2.9 million.

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 will provide a $7 million drilling carry during 2025 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 year-end 2024 are $1.4 million.

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

During 2024, we realized net income of $1.9 million as compared to net income of $6.9 million for 2023.

At December 31, 2023, our total estimated net proved developed reserves were 50,681 MMcfe, a decrease of 37% from December 31, 2022.

The decrease is mainly attributable to revisions to previous estimates related to commodity pricing.

At December 31, 2023, our total estimated net proved reserves were 70,262 MMcfe, a 25% decrease from December 31, 2022.

The primarily price-related decrease in our total proved developed reserves was partially offset by increases in proved undeveloped reserves in PA from wells currently in progress.

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.

At December 31, 2024, our total estimated net proved developed reserves were 64,872 MMcfe, a 28% increase from December 31, 2023.

The increase is mainly attributable to transfers from proved undeveloped reserves in Pennsylvania and acquisitions in Texas.

At December 31, 2024, our total estimated net proved reserves were 84,097 MMcfe, a 20% increase from December 31, 2023.

This increase is primarily due to revisions in previous estimates related to changes to previously adopted development plans and well performance and acquisitions in Texas 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 must have confirmation from the operator on near-term development to designate an undeveloped well location as proved.

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

During the year ended December 31, 2023, revenues decreased $39.3 million, or 56%, to $30.7 million from $70.0 million during the year ended December 31, 2022 primarily due to lower realized natural gas prices in PA (down 71%), partially offset by new oil revenues from the Permian Basin.

During the year ended December 31, 2024, revenues increased $0.8 million, or 3%, to $31.5 million from $30.7 million during the year ended December 31, 2023.

Revenue and volume statistics for the years ended December 31, 2024 and 2023 were as follows:

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Total OK Revenues

Oil and condensate revenue

Volume (MBbl)

Price ($/Bbl)

Total Canada Revenues

Total Revenues

Upstream natural gas revenue for the year ended December 31, 2024 decreased by $4.1 million, or 27%, from 2023.

A decrease of $35.1 million was due to lower realized natural gas prices and a reduction of $7.0 million was due to lower produced volumes due to natural decline of the wells.

Upstream natural gas liquids revenue for the year ended December 31, 2023 decreased by $0.7 million, or 43% from 2022.

A decrease of $0.5 million was due to lower natural gas liquids prices and a reduction of $0.2 million was due to lower produced volumes.

A decrease of $0.2 million was due to lower natural gas prices and a decrease of $3.9 million was due to lower produced 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 year ended December 31, 2024 increased by $0.5 million, or 51% from 2023.

An increase of $0.8 million was due to higher produced volumes from new wells in the Permian Basin and a reduction of $0.3 million was due to lower natural gas liquids prices.

Upstream oil and condensate revenue for the year ended December 31, 2024 increased by $8.6 million, or 170% over 2023.

An increase of $9.4 million was due to increased production from new wells in the Permian Basin offset by a reduction of $0.8 million due to lower oil prices.

Gathering system revenue for the year ended December 31, 2023 increased by $1.7 million, or 21% over 2022.

This was the result of anchor shipper volumes, which pay the full gathering rate, increasing from 69% to 78% of total

throughput in addition to a one-time compressor fee adjustment as a result of the operator’s internal audit of the gathering system.

Gathering system revenue (net of elimination) for the year ended December 31, 2024 decreased by $4.3 million, or 44% over 2023.

The decrease was primarily due to lower anchor shipper volumes as a result of natural decline in the wells and operator elected well shut-ins due to poor natural gas pricing in Pennsylvania partially offset by an increase in the Auburn gathering rate.

Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.1 million and $1.4 million, respectively, for the years ended December 31, 2024 and 2023.

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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, 2023, upstream operating costs decreased by $0.7 million, or 10.1% from the same period in 2022.

Operating costs in 2022 were higher due to higher produced volumes and 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.

For the year ended December 31, 2024, upstream operating costs increased by $0.9 million, or 13.4% from the same period in 2023.

The increase is primarily due to the acquired and developed wells in the Permian Basin.

The higher unit operating cost is primarily due to the higher liquids (oil and natural gas liquids) proportion of total 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 year ended December 31, 2023, gathering system operating costs increased by $0.2 million, or 7.5% from the same period in 2022.

For the year ended December 31, 2024, gathering system operating costs decreased by $0.2 million, or 7.9% from the same period in 2023.

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

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During the year ended December 31, 2024, DD&A expense increased by $2.5 million, or 33%, compared to the same period in 2023.

This increase was a result of the lower reserves causing an increased depletion rate in addition to four new producing wells in the Permian Basin.

Loss (gain) on Sale of Assets

This increase was a result of the lower third-party reserves causing an increased depletion rate in addition to higher production from the Permian Basin.

Year ended December 31,

Loss (gain) on sale of assets

For the year ended December 31, 2023, the Company had a loss on sale of assets of $1.4 million, compared to a gain of $0.2 million in 2022 due to the assets sold in 2023 having a larger net book value than the asset sold in 2022.

Epsilon sold two Oklahoma assets in April 2023 and one Oklahoma asset in April 2022.

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 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.

For the year ended December 31, 2024, the Company recorded an impairment of $1.45 million on the Killam project (interest acquired in April 2024) in Alberta, Canada.

One well was impaired as a result of a decrease in reserves ($0.53 million) and one well drilled during the year was deemed non-commercial ($0.92 million).

For the year ended December 31, 2023, there was no impairment.

General and Administrative (“G&A”)

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General and administrative

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 were generally consistent compared to the same period in 2022, decreasing by $0.03 million, or 0%.

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

G&A expenses for the year ended December 31, 2024 decreased by $0.3 million, or 5%, compared to the same period in 2023.

This decrease was primarily due to a reduction in legal expenses.

Interest Income

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Interest income

During the year ended December 31, 2023, interest income increased by $1.2 million, or 269%, from the same period in 2022.

This increase was primarily due to the utilization of additional financial instruments with higher prevailing interest rates in 2023.

During the year ended December 31, 2024, interest income decreased by $1.2 million, or 71%, from the same period in 2023.

This decrease was primarily due to the reduction in the balance of cash and short term investments.

Interest Expense

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

Interest expense increased by $0.03 million, or 58%, during the year ended December 31, 2023 from 2022.

The increase is due to the front-end fees on our new credit facility put in place during 2023.

Net gain (loss) on commodity contracts

Interest expense decreased by $0.03 million, or 42%, during the year ended December 31, 2024 from 2023.

The decrease is due to higher fees in 2023 associated with our new credit facility.

Net (loss) gain on commodity contracts

Year ended December 31,

Gain on derivative contracts

During the year ended December 31, 2023, the Company had NYMEX Henry Hub (“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 year ended December 31, 2022, the Company had NYMEX HH two-way collars and Tennessee Gas Pipeline Zone 4 basis swap derivative contracts for the same hedging purpose.

(Loss) gain on derivative contracts

During the year ended December 31, 2024, the Company had NYMEX Henry Hub (“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.

During the year ended December 31, 2023, the Company had NYMEX HH Natural Gas Futures swaps and Tennessee Gas Pipeline Zone 4 basis swaps derivative contracts for the same hedging purpose.

The amounts recorded represent the fair value changes on our derivative instruments during the year.

For the year ended December 31, 2024, the Company received net cash settlements of $1,196,656.

For the year ended December 31, 2022, the Company paid net cash settlements of $1,225,837.

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

In September 2023, the Company added NYMEX HH swaps totaling 0.38 Bcf with a strike price of $3.315 and Tennessee Z4 basis swaps totaling 0.38 Bcf with a strike price of ($0.73) to hedge a portion of the expected volumes for the contract period of November 2023 to March 2024.

The Company also added NYMEX HH swaps totaling 1.07 Bcf with a strike price of $3.1975 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a strike price of ($1.145) to hedge a portion of the expected volumes for the contract period of April 2024 to October 2024.

In October 2023, the Company added NYMEX HH swaps totaling 0.38 Bcf with a strike price of $3.455 and Tennessee Z4 basis swaps totaling 0.38 Bcf with a strike price of ($0.81) to hedge a portion of the expected volumes for the contract period of November 2023 to March 2024.

The Company also added NYMEX HH swaps totaling 0.535 Bcf with a strike price of $3.29 and Tennessee Z4 basis swaps totaling 0.535 Bcf with a strike price of ($1.20) to hedge a portion of the expected volumes for the contract period of April 2024 to October 2024.

For the year ended December 31, 2023, the Company received net cash settlements of $3,251,890.

At December 31, 2024, the Company had outstanding NYMEX HH swaps totaling 2.2615 Bcf with a weighted average strike price of $3.26 and Tennessee Z4 basis swaps totaling 2.2615 Bcf with a weighted average strike price of ($0.91) for the contract period of January 2025 to October 2025, and NYMEX WTI CMA swaps totaling 20,662 Bbls with a weighted average strike price of $73.49 for the contract period of January 2025 to June 2025.

At December 31, 2023, the Company had outstanding NYMEX HH swaps totaling 1.905 Bcf with a weighted average strike price of $3.25 and Tennessee Z4 basis swaps totaling 1.905 Bcf with a weighted average strike price of ($1.10) to hedge a portion of expected volumes for the contract period of January 2024 to October 2024.

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During the year ended December 31, 2024, income tax expense decreased by $1.6 million, or 49%, from the same period in 2023.

This decrease was primarily due to a decrease in taxable income as a result of lower realized commodity prices.

This decrease was primarily due to a decrease in taxable income as a result of losses on derivative contracts and higher intangible drilling cost deductions.

Net Income Compared to Adjusted EBITDA

Year ended December 31,

Interest (income) expense, net

Interest income, net

Income tax expense

Depreciation, depletion, amortization, and accretion

Impairment expense

Stock based compensation expense

Gain (loss) on sale of assets

Loss (gain) on derivative contracts net of cash received or paid on settlement

Loss on sale of assets

Loss on derivative contracts net of cash received or paid on settlement

Foreign currency translation loss

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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.

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.

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Capital Resources and Liquidity

The primary source of cash during the years ended December 31, 2023 and 2022 was funds generated from operations.

The primary source of cash during the year ended December 31, 2024 was funds generated from operations and proceeds from short term investments.

The primary source of cash during the year ended December 31, 2023 was funds generated from operations.

For the year ended December 31, 2024 the primary uses of cash were the acquisition and development of upstream properties and the distribution of dividends.

For the year ended December 31, 2023 the primary uses of cash were the acquisition and development of upstream properties, investment in U.S.

Treasury bills, the repurchase of shares of common stock, and the distribution of dividends.

For the year ended December 31, 2022, cash was primarily used for the development of upstream properties, the repurchase of common stock, and the distribution of dividends.

At December 31, 2024, we had a working capital surplus of $7.0 million, a decrease of $26.2 million from the $33.2 million surplus at December 31, 2023.

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During the year ended December 31, 2024, $16.8 million was provided by our operating activities, compared to $18.2 million in 2023, a $1.4 million, or 7%, decrease.

The decrease was mainly due to the decrease in realized prices resulting in decreased revenue.

The company used $37.7 million for investing activities during the year ended December 31, 2023, compared to $7.9 million in 2022, a $29.8 million, or 379%, increase.

The Company made a $17.9 million investment in U.S.

Treasury bills and $19.8 million in capital investment in the upstream properties.

During the year ended December 31, 2023, $11.7 million of cash used for financing activity was primarily related to the repurchase of our common shares and the payment of quarterly dividends.

During the year ended December 31, 2022, $12.0 million of cash used for financing activity was primarily 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.

The decrease was primarily due to lower production and throughput volumes in the Marcellus due to operator elected shut-ins, offset by higher production volumes in Texas.

The company used $16.7 million for investing activities during the year ended December 31, 2024, compared to $38.4 million in 2023, a $21.7 million, or 57%, decrease.

The decrease was primarily due to a $40.8 million decrease in purchases of short-term investments, offset by a $15.2 million increase in capital investments in upstream properties.

During the year ended December 31, 2024, the Company used $7.3 million for financing activity compared to $11.7 million in 2023, a $4.4 million, or 38% decrease.

The decrease was due to fewer repurchases of our common shares.

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 new facility replaced the Company’s previous facility.

The initial commitment and borrowing base is $35 million (redetermined as of December 6, 2023), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of the earlier of June 28, 2027.

The current borrowing base is $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%.

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Repurchase Transactions

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 our outstanding common shares, for an aggregate purchase price of not more than US $15.0 million.

The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act.

The program commenced on March 27, 2023, and will end on March 26, 2024, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.

During the year ended December 31, 2023, we repurchased 968,149 common shares and spent $4,940,295 at an average price of $5.08 per share (excluding commissions) under the new plan.

On March 19, 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 was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act.

The program commenced on March 27, 2024 and was set to expire on March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.

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.

The previous share repurchase program commenced on March 9, 2023.

During the year ended December 31, 2023, we repurchased 968,149 common shares of the maximum of 2,292,644 authorized for repurchase and spent $4,940,295 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 and retired 190,700 common shares and spent $1,115,306 at an average price of $5.82 per share (excluding commissions) before the plan terminated on March 7, 2023.

The repurchased stock had an average price of $5.08 per share (excluding commissions) and 897,275 common shares were retired during the year ended December 31, 2023.

In 2024, we repurchased 248,700 common shares and spent $1,203,708 at an average price of $4.82 per share (excluding commissions) and retired 319,574 common shares before the plan terminated on March 26, 2024.

In 2024, the Company repurchased 373,700 shares and spent $1,831,208 at an average price of $4.88 per share (excluding commissions) under the two consecutive repurchase programs.

On March 19, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $12.0 million.

On February 12, 2025, 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 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, 2024 and end on March 26, 2025, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.

The program will commence on February 12, 2025 and end on February 11, 2026, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.

Derivative Transactions

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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, 2023, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following:

At December 31, 2024, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:

Weighted Average

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Tennessee Z4 basis swap

Weighted Average

Derivative Type

Price ($/Bbl)

Crude Oil NYMEX WTI CMA

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.

As of December 31, 2023, our commitments for capital expenditures were nil.

As of December 31, 2024, our commitments for capital expenditures were $7.8 million.

All of the capital commitments are related to the first two wells of the joint venture in Alberta entered into in October 2024.

Of the total commitment, $3.4 million is drilling carry in favor of the operator, the remaining amount is our working interest share of outstanding authorizations for future expenditures.

Summary of Critical Accounting Estimates

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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.

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.

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In addition, such assumptions and estimates are reasonably likely to change in the future.

inputs used to determine the fair values of proved properties include estimates of:

Significant inputs used to determine the fair values of proved properties include estimates of:

(i) reserves;

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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 re-assessments.

Income tax filings are subject to audits and

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.

2 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis