What changed in this filing

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Item 7. Management’s Discussion and Analysis

2024-03-18 compared with 2023-03-29 · 49 added, 82 removed, 180 unchanged (42% of the section changed)

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In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies.

Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “ Permian Basin ”) and in the Denver-Julesberg Basin (“ D-J Basin ”) in Colorado.

As of December 31, 2022, we held approximately 31,308 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned operating subsidiary, PEDCO and approximately 12,372 net D-J Basin acres located in Weld and Morgan Counties, Colorado, through our wholly-owned operating subsidiary, Red Hawk.

As of December 31, 2022, we held interests in 381 gross (377 net) wells in our Permian Basin Asset, of which 42 are active producers, 16 are active injectors and two are active SWD’s, all of which are held by PEDCO and operated by its wholly-owned operating subsidiaries, and interests in 92 gross (24.1 net) wells in our D-J Basin Asset, of which 18 gross (16.2 net) wells are operated by Red Hawk and currently producing, 53 gross (7.9 net) wells are non-operated, and 21 wells have an after-payout interest.

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.

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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production volumes;

realized prices on the sale of oil and natural gasgas;

realized prices on the sale of oil and natural gas;

oil and natural gas production and operating expenses;

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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.

Total reserve value at December 31, 2022, represents an increase of approximately $177.8 million or 90% from approximately $196.7 million a year earlier using the same SEC pricing and reserves methodology.

The increase is strictly attributable to commodity pricing as the average pricing for 2022, noted above, was significantly higher than the 2021 average pricing of $66.56 per Bbl for crude oil and $3.598 per Mcf for natural gas.

Total reserve value at December 31, 2023, represents a decrease of approximately $142.8 million or 38% from approximately $374.5 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 reserves as of December 31, 2023 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc.

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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 primarily driven by two main factors including, production from two new wells in the operated Permian Basin asset which came online in Q2 2022, and the positive performance from our participation in non-operated wells in the D-J Basin Asset which came online in Q1 2022 (see additional detail below).

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).

Significant Capital Expenditures

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Leasehold Acquisitions

Mineral Acquisitions

Drilling and Facilities

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Financial Statements and Supplementary Data ”).

Net Income (Loss)

We reported net income for the year ended December 31, 2022 of $2.8 million, or $0.03 per share, compared to a net loss for the year ended December 31, 2021 of $1.3 million or ($0.02) per share.

The increase in net income of $4.1 million was primarily due to a $14.2 million increase in revenue, offset by an increase of $7.9 million in total operating expenses in the current period, offset further by a $0.4 million gain from forgiveness of our $0.4 million Paycheck Protection Program loan in May 2021, coupled with a $1.8 million gain on sale of oil and gas properties each in the prior period (all of which are discussed in more detail below).

On June 2, 2020, the Company received loan proceeds of $370,000 (the “ PPP Loan ”) under the Small Business Association (SBA) Paycheck Protection Program.

The PPP Loan was evidenced by a promissory note, dated as of May 28, 2020 (the “ Note ”), between the Company and Texas Capital Bank, N.A.

The Note had a two-year term, bears interest at the rate of 1.00% per annum, and may be prepaid at any time without payment of any premium.

Effective May 20, 2021, the Company received notification from Texas Capital Bank, N.A.

that the SBA had fully forgiven the Company’s PPP Loan principal and accrued interest of $370,000 and $4,000, respectively.

Therefore, as of December 31, 2021, the Company recognized no debt or accrued interest related to the PPP Loan on the balance sheet, and a gain on forgiveness of PPP Loan of $374,000 for the year ended December 31, 2021 in connection with such forgiveness.

We reported net income for the year ended December 31, 2023 of $0.3 million, or $0.00 per share, compared to net income for the year ended December 31, 2022 of $2.8 million or $0.03 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 following table sets forth the revenue and production data for the years ended December 31, 2023 and 2022:

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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, 2022, increased $14.2 million, or 89%, to $30.0 million, compared to $15.9 million for the same period a year ago, due primarily to a favorable volume variance of $7.9 million, coupled with a favorable price variance of $6.3 million.

The increase in production volume is primarily driven by two main factors including, production from two new wells in the operated Permian Basin asset in Q2 2022, and the positive performance from our participation in non-operated wells in the D-J Basin Asset in Q1 2022.

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.

Net Operating and Other (Income) Expenses

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Total General and Administrative Expense

Gain on Sale of Oil and Gas Properties

Interest Expense

Loss on Sale of Oil and Gas Properties

Interest Income

Gain on forgiveness of PPP loan

*Includes severance, ad valorem taxes and marketing costs.

Lease Operating Expenses.

The increase of $4.5 million was primarily due to increased overall activity compared to the prior period as well as increased taxes and marketing fees from higher production volumes.

Also, additional workovers for well reactivations, artificial lift repairs and optimizations have been executed during the current period in an effort to maximize production volumes during the current increased commodity pricing environment.

Workover expense included approximately $0.7 million of one-time non-recurring operating expenses for improving the Permian Basin Asset’s water handling infrastructure and approximately $0.5 million of non-recurring costs for environmental cleanup and reclamations of historic well and facility sites that were inherited from previous operators in our Permian Basin Asset.

Increased commodity pricing period over period caused increased production taxes coupled with increased marketing fees from higher production volumes.

Service and materials costs have also increased accordingly with general supply chain and inflation issues seen throughout the industry leading to increased operating and workover costs.

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.

Depreciation, Depletion, Amortization and Accretion.

The $3.8 million increase was primarily the result of an increase in production (noted above) in the current period when compared to the prior period.

Also, as production increased during the period, there was a corresponding decrease in our proved developed reserves in our December 31, 2022 reserve report.

This resulted in a reduction in our depletable base in our Permian Basin Asset, which, in turn caused our depletion rate to increase from 28.21% to 37.86%.

This increase resulted in approximately $2.1 million in additional depletion expense in Q4 2022.

The decrease in proved developed producing reserves in our Permian Basin Asset was related to the natural decline in production from existing wells and pushing the drilling and completion of certain Permian Basin Asset wells into future periods due to timing and allocation of capital to D-J Basin Asset projects.

Additionally, the Company elevated its plugging and abandonment program in the Permian Basin Asset (in accordance with the terms of a new compliance order) to plug additional wells over the next two years, which increased accretion expense in Q4 2022 by approximately $0.5 million.

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.

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

There was no change in general and administrative expenses (excluding share-based compensation) as the Company continues to strive to contain costs and remain within budget from period to period.

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.

Share-Based Compensation.

Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, decreased by $0.4 million primarily due to the forfeiture of certain employee stock-based options and nonvested restricted shares due to certain voluntary employee terminations.

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.

Gain on Sale of Oil and Gas Properties.

The Company sold rights to 230 net acres and interests in three non-operated wells located in the D-J Basin for net cash proceeds of $1.9 million and recognized a gain on sale of oil and gas properties of $1.8 million during the year ended December 31, 2021.

The Company had no sales of oil and gas properties during the year ended December 31, 2022.

Interest Expense.

The $0.01 million of interest expense in the prior period was due to accrued interest related to the Company’s PPP Loan, which was forgiven in the prior period (see above for more information).

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.

Financial Statements and Supplementary Data ” - “ Note 6 - Oil and Gas Properties ”).

Interest Income and Other Expense.

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

Other income in the current 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 is 100% owned and controlled by Dr.

Simon Kukes, our Chief Executive Officer and director, offset by a $15,000 royalty adjustment.

The prior period other income consisted primarily of $0.1 million in accounts payable settlements and other miscellaneous income items.

Gain on forgiveness of PPP loan .

Includes principal and accrued interest from our PPP Loan that was fully forgiven during the prior period (see above for more information).

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.

Liquidity and Capital Resources

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The primary uses of cash were funds used for drilling, completion, acquisition and operating costs.

Impact of COVID-19

In December 2019, a novel strain of coronavirus, which causes the infectious disease known as COVID-19, was reported in Wuhan, China.

The World Health Organization declared COVID-19 a “ Public Health Emergency of International Concern ” on January 30, 2020, and a global pandemic on March 11, 2020.

COVID-19 and the governmental responses thereto significantly reduced worldwide economic activity during much of 2020.

On January 30, 2023, the Biden Administration announced it will end the public health emergency (and national emergency) declarations on May 11, 2023.

During 2021 and 2022, oil and gas prices increased above pre-pandemic levels, and the effect of the pandemic on the Company’s operations in 2022 was minimal.

The extent to which the COVID-19 outbreak will continue to impact the Company’s results will depend on future developments that are highly uncertain and cannot be predicted, including virus mutations and future governmental actions.

Any future decrease in the price of oil, or the demand for oil and gas, as a result of COVID-19, recessions, or otherwise, will likely have a negative impact on our results of operations and cash flows.

Ukraine Conflict

In late February 2022, Russia launched a significant military action against Ukraine.

The conflict has caused, and could intensify, volatility in natural gas, oil and NGL prices, and the extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.

We believe that the increase in crude oil prices during the first half of 2022 was partially due to the impact of the conflict between Russia and Ukraine on the global commodity and financial markets, and in response to economic and trade sanctions that certain countries have imposed on Russia.

Working Capital

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, while at December 31, 2022, the Company’s total current assets of $32.1 million exceeded its total current liabilities of $17.0 million, resulting in a working capital surplus of $15.1 million.

The $7.7 million decrease in our working capital surplus is primarily related to accrued capital expenditures related to our participation in the drilling and completion of six well 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 as a result of our oil and gas sales (described above).

The Company has an ongoing $3.6 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 ”).

On June 10, 2022, the Company sold 87,121 shares of common stock at a sales price of $1.66 per share in the ATM Offering for net proceeds of $141,000, which includes $4,000 in commission fees.

The Company also incurred $106,000 in initial and subsequent legal and audit fees for registration 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 ”).

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

The Company currently has $3.5 million remaining available in securities which we may sell in the future via the Sales Agreement, subject to availability under the Company’s shelf-registration, which limits the maximum amount of securities which can be sold in any 12 month period to 1/3 of the Company’s then public float.

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.

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

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

We periodically review our capital expenditures and adjust our capital forecasts and allocations based on liquidity, drilling results, leasehold acquisition opportunities, partner non-consents, proposals from third party operators, and commodity prices, while prioritizing our financial strength and liquidity (see “ Part I ” – “ Item 1A.

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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.

Our 2023 development program incorporates service costs that have remained relatively flat, based on costs we have experienced since the end of the third quarter of 2022.

Our 2024 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.

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 2024 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) equity infusions or loans (which may be convertible) made available from Dr.

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

Kukes under no obligation to provide, (iv) public or private debt or equity financings, including up to $3.5 million in securities which we may sell in the future in an on-going “at the market offering”, subject to availability under the Company’s shelf-registration, which limits the maximum amount of securities which can be sold in any 12 month period to 1/3 of the Company’s then public float, and (v) funding through credit or loan facilities.

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.

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Cash flows provided by financing activities

Net increase in cash and restricted cash

Net (decrease) increase in cash and restricted cash

Cash provided by operating activities.

Net cash provided by operating activities increased by $10.0 million for the current year’s period, when compared to the prior year’s period, primarily due to an increase in net income of $4.1 million, coupled with a $3.8 million increase in depreciation, depletion and amortization (due to increased sales production), and by a $0.1 million net decrease to our other components of working capital in the current period.

During the year ended December 31, 2021, we also had a $1.8 million gain on the sale of oil and gas properties and a $0.4 million gain from forgiveness of our PPP Loan.

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).

Cash used in investing activities.

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Cash provided by financing activities.

In the prior period, the Company closed an underwritten public offering of 5,968,500 shares of common stock at a public offering price of $1.50 per share, which included the full exercise of the underwriter’s over-allotment option, for net proceeds (after deducting the underwriters’ discount equal to 6% of the public offering price and expenses associated with the offering) of $8.2 million, net of offering costs.

The current period sales of our common stock via our ATM Offering are discussed above.

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.

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.

Non-GAAP Financial Measures

We have included EBITDA and Adjusted EBITDA in this Report as supplements to GAAP measures of performance to provide investors with an additional financial analytical framework which management uses, in addition to historical operating results, as the basis for financial, operational and planning decisions and present measurements that third parties have indicated are useful in assessing the Company and its results of operations.

We have included EBITDA and Adjusted EBITDA in this Report as supplements to generally accepted accounting principles in the United States of America (“ GAAP ”) measures of performance to provide investors with an additional financial analytical framework which management uses, in addition to historical operating results, as the basis for financial, operational and planning decisions and present measurements that third parties have indicated are useful in assessing the Company and its results of operations.

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

“Adjusted EBITDA” represents EBITDA, less share-based compensation, gain on sale of oil and gas properties, gain on forgiveness of the PPP Loan, and accounts payable settlements.

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

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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Depreciation, depletion, amortization and accretion

Interest expense

Share-based compensation

Gain on sale of oil and gas properties

Gain on forgiveness of PPP loan

Accounts payable settlements

Loss on sale of oil and gas properties

Adjusted EBITDA

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Recently Adopted Accounting Pronouncements.

The Company does not expect the adoption of any other recently issued accounting pronouncements to have a significant impact on its financial position, results of operations, or cash flows.

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.

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.

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

Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures.

This ASU will be effective for the annual period ending December 31, 2025.

The Company is currently evaluating the timing and impacts of adoption of this ASU.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.

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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