What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2025-03-31 compared with 2024-03-18 · 76 added, 52 removed, 177 unchanged (42% of the section changed)

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See “ Risk Factors ” and “ Forward-Looking Statements .

The discussion in this section has been impacted by the restatement described in the Explanatory Note at the beginning of this Annual Report on Form 10-K and in Note 4 of the consolidated financial statements.

Certain of the financial and other information provided in this Management’s Discussion and Analysis of our financial condition and results of operations has been updated to reflect the restatement adjustments.

Summary of The Information Contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations

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An analysis of changes in our consolidated balance sheets and cash flows and discussion of our financial condition.

Critical Accounting Policies and Estimates .

Critical Accounting Estimates .

Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts.

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Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico and in the Denver-Julesberg Basin in Colorado and Wyoming.

As of December 31, 2023, we held approximately 22,721 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, PEDCO, and which are operated by our wholly-owned operating subsidiary, RAZO, which asset we refer to as our “ Permian Basin Asset .” Also as of December 31, 2023, we held approximately 14,282 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and 4,931 net D-J Basin acres located in Laramie County, Wyoming, through our wholly-owned subsidiary, PRH, and which are operated by our wholly-owned operating subsidiary, Red Hawk, which asset we refer to as our “ D-J Basin Asset .” As of December 31, 2023, we held interests in 300 gross and net wells in our Permian Basin Asset, of which 25 are active producers, two are active injectors and two are active salt water disposal wells, all of which are held by PEDCO and operated by RAZO, and interests in 98 gross (24.6 net) wells in our D-J Basin Asset held by PRH, all of which 18 gross (16.2 net) wells are operated by Red Hawk and currently producing, 63 gross (8.4 net) wells are non-operated, and 17 wells have an after-payout interest.

As of December 31, 2024, we held approximately 14,105 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, PEDCO, and which are operated by our wholly-owned operating subsidiary, RAZO, which asset we refer to as our “ Permian Basin Asset .” Also as of December 31, 2024, we held approximately 14,809 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and 3,860 net D-J Basin acres located in Laramie County, Wyoming, through our wholly-owned subsidiary, PRH, and which are operated by our wholly-owned operating subsidiary, Red Hawk, which asset we refer to as our “ D-J Basin Asset .” As of December 31, 2024, we held interests in 35 gross (33.5 net) wells in our Permian Basin Asset, of which 28 gross (26.5 net) wells are active producers, five gross (five net) wells are inactive, and two gross (two net) wells are active salt water disposal wells (“ SWD’ s”), all of which are held by PEDCO and operated by RAZO, and interests in 82 gross (21.9 net) wells in our D-J Basin Asset held by PRH, all of which 17 gross (15.4 net) wells are operated by Red Hawk and currently producing, 48 gross (6.5 net) wells are non-operated, and 17 wells have an after-payout interest.

Detailed information about our business plans and operations, including our core D-J Basin and Permian Basin Assets, is contained under “ Part 1 ” — “ Item 1.

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net cash provided by operating activities;

Our estimated net proved crude oil and natural gas reserves at December 31, 2023 and 2022 were approximately 17.0 MMBoe and 16.1 MMBoe, respectively.

Our estimated net proved crude oil and natural gas reserves at December 31, 2024 and 2023 were approximately 18.1 million barrels of oil equivalent (“ MMBoe ”) and 17.0 MMBoe, respectively.

The 1.1 MMBoe increase was primarily due to the addition of proved undeveloped reserves in our D-J Basin Asset as a result of increased activity around our acreage and favorable pricing.

Using the average monthly crude oil price of $78.22 per Bbl and natural gas price of $2.64 per thousand cubic feet (“ Mcf ”) for the twelve months ended December 31, 2023, our estimated discounted future net cash flow (“ PV-10 ”) for our proved reserves was approximately $231.7 million, of which approximately $149.0 million are proved undeveloped reserves.

Using the average monthly crude oil price of $75.48 per barrel (“ Bbl ”) and natural gas price of $2.13 per thousand cubic feet (“ Mcf ”) for the twelve months ended December 31, 2024, our estimated discounted future net cash flow (“ PV-10 ”) for our proved reserves was approximately $178.9 million, of which approximately $104.3 million are proved undeveloped reserves.

Total reserve value at December 31, 2024, represents a decrease of approximately $52.8 million or 23% from approximately $231.7 million a year earlier using the same SEC pricing and reserves methodology.

The decrease is primarily attributable to commodity pricing, as the average pricing for 2023, noted above, was significantly lower than the 2022 average pricing of $93.67 per Bbl for crude oil and $6.36 per Mcf for natural gas.

The decrease is primarily attributable to commodity pricing, as the average SEC pricing for 2024, noted above, was lower than the 2023 average pricing of $78.22 per Bbl for crude oil and $2.64 per Mcf for natural gas.

The reserves as of December 31, 2024 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc.

A large portion of the proved undeveloped crude oil reserves are associated with our Permian Basin Asset.

A large portion of the proved undeveloped crude oil reserves are associated with our D-J Basin Asset.

Although these hydrocarbon quantities have been determined in accordance with industry standards, they are prepared using the subjective judgments of the independent engineers and may actually be more or less.

Oil and Natural Gas Sales Volumes

During the year ended December 31, 2023, our net crude oil, natural gas, and NGLs sales volumes increased to 520,886 Bbls, or 1,427 Bopd, from 364,771 Bbls, or 999 Bopd, a 43% increase over the previous fiscal year.

The increase in production volume is related to the positive performance from our participation in 14 non-operated wells in the D-J Basin Asset (six of which began producing in late 2022 and eight of which began producing in the first quarter of 2023), combined with maintaining relatively flat production declines from the existing operated Permian Basin and D-J Basin Assets (see additional detail below).

During the year ended December 31, 2024, our net crude oil, natural gas, and NGLs sales volumes increased to 671,796 Bbls, or 1,835 barrels of oil per day (“ Bopd ”), from 520,886 Bbls, or 1,427 Bopd, a 29% increase over the previous fiscal year.

The increase in production volume is related to our participation in 24 new non-operated wells (11 of which occurred in the latter four months of 2024) in the D-J Basin and the drilling and completion of three operated wells with a third-party in the Permian Basin in the latter part of Q1 2024 (see additional detail below).

Significant Capital Expenditures

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We reported net income for the year ended December 31, 2024 of $17.8 million, or $0.20 per share, compared to net income for the year ended December 31, 2023 of $1.7 million or $0.02 per share.

The decrease in net income of $2.5 million was primarily due to a $4.3 million loss on the sale of our EOR subsidiary, offset by a $0.8 million increase in revenue and by a decrease of $0.7 million in total operating expenses in the current period, offset further by a $0.3 million increase in other income (all of which are discussed in more detail below).

The increase in net income of $16.1 million was primarily due to a recognition of an income tax benefit of $12.8 million (see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 14 – Income Taxes ”) coupled with $8.8 million increase in revenue in the current period and a $4.3 million loss on the Milnesand Sale in the prior period, offset by a $9.5 million increase in total operating expenses in the current period, offset further by a $0.2 million decrease in other income and a $0.1 million loss on sale of oil and gas properties in the current period (all of which are discussed in more detail below).

The following table sets forth the revenue and production data for the years ended December 31, 2024 and 2023:

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Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil.

Total crude oil, natural gas and NGL revenues for the year ended December 31, 2023, increased $0.8 million, or 2%, to $30.8 million, compared to $30.0 million for the same period a year ago.

Although production increased resulting in a favorable volume variance of $7.4 million, the average sales prices for crude oil, natural gas and NGLs realized by the Company decreased considerably from the year ended December 31, 2022, resulting in an unfavorable price variance of $6.6 million.

Total crude oil, natural gas and NGL revenues for the year ended December 31, 2024, increased $8.8 million, or 28%, to $39.6 million, compared to $30.8 million for the same period a year ago, due to a favorable volume variance of $8.8 million.

There was a negligible price variance over the periods.

The increase in production volume is related to our participation in 24 new non-operated wells in the D-J Basin and the drilling and completion of three operated wells in the Permian Basin.

Net Operating and Other (Income) Expenses

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% Increase (Decrease)

(As Restated)

Direct Lease Operating Expense

Loss (gain) on settlement of ARO

Loss on settlement of ARO

Lease Operating Expenses

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Interest Income

*Includes severance, ad valorem taxes and marketing costs.

Other Income (Expense)

Gain on Sale of Fixed Asset

*Includes severance, ad valorem taxes, workover adjustments and assessment and marketing costs.

Lease Operating Expenses.

Expense reduction measures to control costs have been implemented on our operated properties in our Permian Basin and D-J Basin Assets, such as operation and lift efficiency improvements, resulting in a reduction in direct operating expenses, offset by a corresponding increase in direct operating expenses from our participation in non-operated wells (noted above) when comparing the current period to the prior period.

Other expenses have also increased due to production increases, coupled with a loss related to our plugging of 11 wells in our Permian Basin Asset, offset by a corresponding decrease in workovers when comparing the current period to the prior period.

Taken together, there was a $0.6 million decrease in overall lease operating expenses when comparing periods.

The increase of $2.6 million was primarily due to higher direct and variable lease operating expenses associated with the higher oil volume resulting from the increased number of wells and increased oil and gas production during the current year’s period, compared to the prior year’s period.

Depreciation, Depletion, Amortization and Accretion.

The $0.3 million decrease was primarily the result of a $0.5 million decrease in accretion expense from the sale of our wholly owned subsidiary EOR Operating Company and related assets, (noted below) offset by a $0.2 million increase in depletion expense from increased production (noted above) in the current period when compared to the prior period.

The $5.9 million increase was primarily the result of an increase in production (noted above) in the current period when compared to the prior period.

Additionally, the Company continued to adhere to its plugging and abandonment program in the Permian Basin Asset (in accordance with the terms of an existing compliance order) to plug additional wells over the next several years, which increased accretion expense in Q4 2024 by approximately $0.4 million.

General and Administrative Expenses (excluding share-based compensation).

The increase of $0.2 million in general and administrative expenses (excluding share-based compensation) was primarily due to the addition of a new employee, an increase in accrued bonuses, which were subsequently paid in January 2023, and general increases in accounting and professional services when comparing the prior period to the current period.

The increase of $0.6 million in general and administrative expenses (excluding share-based compensation) was primarily due to increased contract and full time staff related to increased activity, an increase in accrued bonuses, which were subsequently paid in January 2025, software licensing fees and general increases in accounting and professional services when comparing the prior period to the current period.

Share-Based Compensation.

Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, decreased nominally due to the forfeiture of certain employee stock-based options due to certain voluntary employee terminations in the prior period, offset by the issuance of restricted shares of common stock to board members in the current period.

Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations.

Loss on Sale of Oil and Gas Properties.

The Company sold its wholly owned subsidiary EOR Operating Company and related assets in November 2023 and recognized the corresponding loss of $4.3 million (see “ Item 8.

Loss on Sale of Oil and Gas Properties, net .

The Company completed three oil and gas property sales transactions during the year ended December 31, 2024, for a total net loss on the sale of oil and gas properties of $76,000, as follows:

(i) the Company sold 30 gross (5.1 net) non-operated legacy well-bores in its D-J Basin Asset for net cash proceeds of $90,000 during 2024, resulting in the Company recognizing a loss on sale of oil and gas properties of $865,000 for these non-core assets, while noting.

the Company still retained the corresponding acreage related to the sale for any potential future development;

(ii) the Company sold a legacy well-bore assignment for net cash proceeds of $25,000 and recognized a gain on sale of oil and gas properties of $29,000;

and (iii) the Company sold leasehold rights to 320 net acres located in the D-J Basin for net cash proceeds of $750,000 and recognized a corresponding gain on sale of oil and gas properties of $735,000, as the leasehold costs had been fully depleted.

In the prior period, the Company sold its then-wholly-owned subsidiary EOR Operating Company and related assets in the November 2023 Milnesand Sale and recognized the corresponding loss of $4.3 million.

(see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”).

Interest Income and Other Expense.

Includes interest earned from our interest-bearing cash accounts, for which interest rates have increased significantly in the current period, compared to the prior period.

Other income in the current period is primarily related to the sale of used pipe while other income in the prior period is primarily related to an $80,000 vendor dispute settlement, coupled with a $24,000 non-refundable two-year rent payment made in September 2022 to the Company for office space leased by SK Energy, which was 100% owned and controlled by Dr.

Kukes, our Chief Executive Officer and director, at the time (which has since been dissolved), offset by a $15,000 royalty adjustment.

Interest Income and Other (Expense) Income.

Includes interest earned from our interest-bearing cash accounts, for which interest rates have remained relatively flat in the current period, compared to the prior period, and interest on our note receivable.

Other expense in the current period primarily relates to the subsequent disposition of a cash escrow bank balance related to the Milnesand Sale.

Other income in the prior period is primarily related to the sale of used pipe.

Gain on Sale of Fixed Asset.

Relates to the sale of a vehicle and the subsequent purchase of another vehicle in the current period.

Liquidity and Capital Resources

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At December 31, 2024, the Company’s total current assets of $13.2 million exceeded its total current liabilities of $6.9 million, resulting in a working capital surplus of $6.3 million, while at December 31, 2023, the Company’s total current assets of $24.6 million exceeded its total current liabilities of $18.9 million, resulting in a working capital surplus of $5.7 million.

The $9.4 million decrease in our working capital surplus is primarily related to decreases in our cash balance related to capital expenditures from our drilling, as operator, three wells in our Permian Basin Asset and our participation in the drilling and completion of 13 wells in our D-J Basin Asset by a third-party operator (see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 6 - Oil and Gas Properties ”) offset by increases in revenue receivables as a result of our oil and gas sales (described above).

Our net capital expenditures for 2024 are estimated at the time of this Annual Report to range between $20 million to $30 million.

This estimate includes a range of $17 million to $27 million for drilling and completion costs on our Permian Basin and D-J Basin Asset and approximately $3 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

Although current assets and current liabilities both decreased when comparing periods, the $0.6 million net increase in our working capital surplus is primarily related to a larger reduction in accounts payable and accrued expenditures compared to the corresponding smaller reduction in current assets when comparing the current period to the prior period due to the timing of cash payments related to our drilling, as operator, and our participation in the drilling and completion of wells by a third-party operator.

(see “ Item 8.

Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”).

The Company has an ongoing $8.0 million offering of securities in an “at the market offering”, pursuant to which the Company may sell securities from time to time (the “ ATM Offering ”).

The ATM Offering was made pursuant to the terms of a December 20, 2024, Sales Agreement (the “ Sales Agreement ”) with Roth Capital Partners, LLC and A.G.P./Alliance Global Partners.

The Company will pay the Lead Agent a commission of 3.0% of the gross sales price of any shares sold under the Sales Agreement.

The Company also agreed to reimburse the Agents for their reasonable and documented out-of-pocket expenses in an amount not to exceed $75,000, in connection with entering into the Sales Agreement and for the Agents’ reasonable and documented out-of-pocket expenses related to quarterly maintenance of the Sales Agreement on a quarterly basis in an amount not to exceed $5,000.

The Company has not sold any securities under the ATM Offering as of the date of this report.

Our net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million, including $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2.5 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and Area of Mutual Interest (AMI) entered into in August 2024 with a private operator.

This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated.

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We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective.

If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and held by production (“ HBP ”), allowing for flexibility of timing on development.

If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and nearly 100% held by production (“ HBP ”), allowing for flexibility of timing on development.

Our 2025 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.

Simon G, Kukes, our Chief Executive Officer and director, which funding Dr.

Kukes under no obligation to provide, and (iv) funding through credit or loan facilities.

In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2024.

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) borrowing under our reserve-based lending facility (“ RBL ”) with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $20 million and an aggregate maximum revolving credit amount of $250 million (of which none has been drawn down by the Company to date), (iv) equity infusions or loans (which may be convertible) made available from Dr.

Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, which funding Dr.

Kukes is under no obligation to provide, (v) public or private debt or equity financings, including up to $8.0 million in securities which we may sell in the future in “at the market offerings”, pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the “ Lead Agent ”), and A.G.P./Alliance Global Partners (“ AGP ” and, together with the Lead Agent, the “ Agents ”)(discussed in greater detail below under “ Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing ” (under which we have sold no shares to date), and (vi) funding through other credit or loan facilities.

In addition, we may seek additional funding through asset sales, farm-out arrangements, and partnerships to fund potential acquisitions during the remainder of 2025.

Cash Flows (in thousands)

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Cash flows provided by financing activities

Net (decrease) increase in cash and restricted cash

Net decrease in cash and restricted cash

Cash provided by operating activities.

Net cash provided by operating activities increased by $7.5 million for the current year’s period, when compared to the prior year’s period, primarily due to a $4.3 million loss on the sale of our EOR subsidiary and its corresponding assets.

Our net income for the period also decreased by $2.6 million when compared to the prior period, additional decreases were primarily from a $0.3 million decrease in depreciation, depletion, amortization and accretion (due to increased sales production and a reduction in accretion expense from our sale of our wholly owned EOR subsidiary), and by a $5.7 million net increase to our other components of working capital in the current period (due to increased drilling and completion activity).

Net cash provided by operating activities decreased by $10.7 million for the current year’s period, when compared to the prior year’s period, primarily due to our net income for the current period increasing by $5.6 million and from a $4.2 million increase in depreciation, depletion, amortization and accretion (primarily due to increased sales production, noted above), offset by a $4.2 million net loss on sale of oil and gas properties (primarily from a $4.3 million loss on the sale of our EOR Operating Company subsidiary and its corresponding assets in the prior period) and by a $16.3 million net decrease to our other components of working capital in the current period (due to increased cash payments and decreased payables and expenses outstanding from our drilling and completion activity) when comparing periods.

Cash used in investing activities.

Net cash used in investing activities increased by $23.5 million for the current year’s period, when compared to the prior year’s period, primarily due to increased capital spending relating to our drilling and completion activities.

Cash provided by financing activities.

In the prior period, we sold our common stock via an “at the market offering” (“ ATM Offering ”), raising net proceeds of $141,000 less commissions, legal and audit fees for registrations and placement of the ATM Offering.

The ATM Offering was made pursuant to the terms of that certain November 17, 2021, Sales Agreement (the “ Sales Agreement ”) with Roth Capital Partners, LLC (“ Roth Capital ”, or the “ Agent ”).

Pursuant to the Sales Agreement the Company agreed to pay the sales agent a commission of 3.0% of the gross sales price of any shares sold under the Sales Agreement, less reimbursement of the first $40,000 of such gross proceeds.

The Company also provided the Agent with customary indemnification rights and has agreed to reimburse the sales agent for certain specified expenses up to $25,000.

Sales under the Sales Agreement were to be made under the Company’s Form S-3 shelf registration statement, which has now expired, and as such, the Company is not currently eligible to sell any additional securities under the Sales Agreement, and, accordingly, was terminated by the Company effective March 15, 2024.

Net cash used in investing activities decreased by $8.9 million for the current year’s period, when compared to the prior year’s period, primarily due to decreased cash outlays from our capital spending relating to our drilling and completion activities.

Cash financing activities.

There were no cash flow financing activities in the current or prior period.

Non-GAAP Financial Measures

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“EBITDA” represents net income before interest, taxes, depreciation and amortization.

“Adjusted EBITDA” represents EBITDA, less share-based compensation and loss on sale of oil and gas properties.

“Adjusted EBITDA” represents EBITDA, less share-based compensation, loss on sale of oil and gas properties, net, and gain on sale of fixed assets.

Adjusted EBITDA excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated.

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The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDA (in thousands):

Net income (loss)

(As Restated)

Income tax benefit

Depreciation, depletion, amortization and accretion

Share-based compensation

Loss on sale of oil and gas properties

Loss on sale of oil and gas properties, net

Gain on sale of fixed assets

Adjusted EBITDA

Critical Accounting Policies and Estimates

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

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Costs specific to developmental wells for which drilling is in progress or uncompleted are capitalized as wells in progress and not subject to amortization until completion and production commences, at which time amortization on the basis of production will begin.

Asset Retirement Obligations.

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made.

The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset.

Asset retirement costs for oil and gas properties are depreciated using the unit-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred.

Accretion expense is included in DD&A expense in the Consolidated Statement of Operations.

Revenue Recognition.

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Recently Adopted Accounting Pronouncements.

On January 1, 2023, we adopted Accounting Standards Update (ASU) No.

2016-13, Measurement of Credit Losses on Financial Instruments , as issued by the FASB.

This standard established the current expected credit loss model, a new impairment model for certain financial instruments, based on expected rather than incurred losses.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280).

The amendments in this update expand segment disclosure requirements, including new segment disclosure requirements for entities with a single reportable segment among other disclosure requirements.

This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.

Adoption of this standard is on a modified retrospective basis and had no impact on the Company’s financial position, results of operations, cash flows or net income per share.

Recently Issued Accounting Pronouncements .

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740):

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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