Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “ forward-looking statements ” that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “ Risk Factors ” and “ Forward-Looking Statements . ”
Summary of The Information Contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is provided in addition to the accompanying consolidated financial statements and notes to assist readers in understanding our results of operations, financial condition, and cash flows. Our MD&A is organized as follows:
●
Overview . Discussion of our business and overall analysis of financial and other highlights affecting us, to provide context for the remainder of our MD&A.
●
Results of Operations . An analysis of our financial results comparing the years ended December 31, 2023 and 2022.
●
Liquidity and Capital Resources . An analysis of changes in our consolidated balance sheets and cash flows and discussion of our financial condition.
●
Critical Accounting Policies and Estimates . Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts.
Overview
We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. 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 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. Business ” above.
How We Conduct Our Business and Evaluate Our Operations
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe have significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
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We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
·
production volumes;
·
realized prices on the sale of oil and natural gas;
·
oil and natural gas production and operating expenses;
·
capital expenditures;
·
general and administrative expenses;
·
net cash provided by operating activities; and
·
net income.
Reserves
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. The 0.9 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. 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. A large portion of the proved undeveloped crude oil reserves are associated with our Permian 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).
Significant Capital Expenditures
The table below sets out the significant components of capital expenditures for the year ended December 31, 2023 (in thousands):
Capital Expenditures
Leasehold Acquisitions
$ 5,211
Mineral Acquisitions
493
Drilling and Facilities
21,573
Total*
$ 27,277
*see “ Item 8. Financial Statements and Supplementary Data ” - “ Note 6 - Oil and Gas Properties ”.
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Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. We expect prices to remain volatile for the remainder of the year. For information about the impact of realized commodity prices on our crude oil and natural gas and condensate revenues, refer to “ Results of Operations ” below.
Results of Operations
The following discussion and analysis of the results of operations for each of the two fiscal years in the years ended December 31, 2023 and 2022 should be read in conjunction with the consolidated financial statements of PEDEVCO Corp. and notes thereto included herein (see “ Item 8. Financial Statements and Supplementary Data ”).
Net Income
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 $0.3 million increase in other income (all of which are discussed in more detail below).
Net Revenues
The following table sets forth the revenue and production data for the years ended December 31, 2023 and 2022:
2023
2022
Increase
(Decrease)
Increase
(Decrease)
Sale Volumes:
Crude Oil (Bbls)
382,794
304,507
78,287
26 %
Natural Gas (Mcf)
479,533
245,923
233,610
95 %
NGL (Bbls)
58,170
19,277
38,893
202 %
Total (Boe) (1)
520,886
364,771
156,115
43 %
Crude Oil (Bbls per day)
1,049
834
215
26 %
Natural Gas (Mcf per day)
1,314
674
640
95 %
NGL (Bbls per day)
159
53
106
200 %
Total (Boe per day) (1)
1,427
999
428
43 %
Average Sale Price:
Crude Oil ($/Bbl)
$ 72.95
$ 90.86
$ (17.91 )
(20%)
Natural Gas($/Mcf)
3.00
6.41
(3.41 )
(53%)
NGL ($/Bbl)
24.43
40.87
(16.44 )
(40%)
Net Operating Revenues (In thousands):
Crude Oil
$ 27,925
$ 27,669
$ 256
1 %
Natural Gas
1,438
1,577
(139 )
(9%)
NGL
1,421
788
633
80 %
Total Revenues
$ 30,784
$ 30,034
$ 750
2 %
(1)
Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil.
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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. 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.
Net Operating and Other (Income) Expenses
The following table sets forth operating and other expenses for the years ended December 31, 2023 and 2022 (in thousands):
2023
2022
Increase (Decrease)
% Increase (Decrease)
Direct Lease Operating Expense
$ 4,679
$ 4,787
$ (108 )
(2%)
Workovers
1,460
2,704
(1,244 )
(46%)
Other*
3,571
2,912
659
23 %
Loss (gain) on settlement of ARO
121
(6 )
127
2,117 %
Lease Operating Expenses
$ 9,831
$ 10,397
$ (566 )
(5%)
Depreciation, Depletion,
Amortization and Accretion
10,875
11,153
(278 )
(2%)
General and Administrative (Cash)
$ 3,965
$ 3,757
$ 208
6 %
Share-Based Compensation (Non-Cash)
2,043
2,097
(54 )
(3%)
Total General and Administrative Expense
$ 6,008
$ 5,854
$ 154
3 %
Loss on Sale of Oil and Gas Properties
4,268
-
4,268
100 %
Interest Income
$ 422
$ 117
$ 305
261 %
Other Income
$ 40
$ 97
$ (57 )
(59%)
*Includes severance, ad valorem taxes 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.
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.
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.
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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. 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 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. Simon G. 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
The primary sources of cash for the Company during the year ended December 31, 2023 were from $30.8 million in sales of crude oil and natural gas. The primary uses of cash were funds used for drilling, completion, acquisition and operating costs.
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 $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).
Financing
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 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. Risk Factors ”).
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. 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.
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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 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.
Cash Flows (in thousands)
Year Ended December 31,
2023
2022
Cash flows provided by operating activities
$ 23,481
$ 15,981
Cash flows used in investing activities
(35,743 )
(12,266 )
Cash flows provided by financing activities
-
35
Net (decrease) increase in cash and restricted cash
$ (12,262 )
$ 3,750
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).
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.
Non-GAAP Financial Measures
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 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. EBITDA and Adjusted EBITDA are presented because we believe they provide additional useful information to investors due to the various noncash items during the period. EBITDA and Adjusted EBITDA are also frequently used by analysts, investors and other interested parties to evaluate companies in our industry. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA and Adjusted EBITDA do not reflect cash expenditures, future requirements for capital expenditures, or contractual commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and EBITDA and Adjusted EBITDA do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments. For example, although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Additionally, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than PEDEVCO Corp. does, limiting its usefulness as a comparative measure. You should not consider EBITDA and Adjusted EBITDA in isolation, or as substitutes for analysis of the Company’s results as reported under GAAP. The Company’s presentation of these measures should not be construed as an inference that future results will be unaffected by unusual or nonrecurring items. We compensate for these limitations by providing a reconciliation of each of these non-GAAP measures to the most comparable GAAP measure. We encourage investors and others to review our business, results of operations, and financial information in their entirety, not to rely on any single financial measure, and to view these non-GAAP measures in conjunction with the most directly comparable GAAP financial measure. 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):
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Years Ended
December 31,
2023
2022
Net income (loss)
$ 264
$ 2,844
Add (deduct)
Depreciation, depletion, amortization and accretion
10,875
11,153
EBITDA
11,139
13,997
Add (deduct)
Share-based compensation
2,043
2,097
Loss on sale of oil and gas properties
4,268
-
Adjusted EBITDA
$ 17,450
$ 16,094
Critical Accounting Policies and 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. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our most significant judgments and estimates used in preparation of our financial statements.
Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise, the related well costs are expensed as dry holes.
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Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above.
Depreciation, depletion and amortization of capitalized oil and gas properties is calculated on a field-by-field basis using the unit of production method. Lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves and all other capitalized costs are amortized over proved developed reserves. 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.
Revenue Recognition. The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.
Contracts with customers have varying terms, including month-to-month contracts, and contracts with a finite term. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.
Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.
Stock-Based Compensation. Pursuant to the provisions of Financial Accounting Standards Board (“ FASB ”) Accounting Standards Codification (“ ASC ”) 718, Compensation – Stock Compensation, which establishes accounting for equity instruments exchanged for employee service, we utilize the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. We estimate volatility by considering historical stock volatility. We have opted to use the simplified method for estimating expected term, which is equal to the midpoint between the vesting period and the contractual term.
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. 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
Not required under Regulation S-K for “ smaller reporting companies .”