EVOLUTION PETROLEUM CORP 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Executive Overview Liquidity and Capital Resources Results of Operations Critical Accounting Policies and Estimates Commonly Used Terms “Current quarter” refers to the three months ended September 30, 2021, the Company's first quarter of fiscal 2022. “Prior quarter” refers to the three months ended June 30, 2021, the Company's fourth quarter of fiscal 2021. “Year-ago quarter” refers to the three months ended September 30, 2020, the Company's first quarter of fiscal 2021. Executive Overview General Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and natural gas properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancements, and other exploitation efforts on its properties. Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO 2 enhanced oil recovery project, our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore central Texas wells. Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%. The field is operated by Denbury, a subsidiary of Denbury, Inc. Our interests in the Hamilton Dome field consist of 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The field is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale consisting of approximately 21,000 net acres held by production across nine North Texas counties in the Barnett Shale. The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2%. At the time of the Barnett Shale acquisition, approximately 90% of the wells acquired were operated by Blackbeard Operating LLC (“Blackbeard”), while the remaining 10% were operated by the seven other operators. After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interest to Diversified Energy Company PLC (“Diversified Energy”), who is presently the operator of the assets. Highlights for our First Quarter of Fiscal 2022 and Operations Update • Produced 5,843 net barrels of oil equivalent per day (“BOEPD”) during the current quarter, up 33% from the quarter ended June 30, 2021 primarily due to a full quarter of production from the Barnett Shale acquisition that closed on May 7, 2021; • Generated net income of $5.2 million ($0.16 per diluted share) in the current quarter, more than double net income of $2.2 million ($0.07 per diluted share) in the prior quarter; • Continued to fund all operations, development capital expenditures, and cash dividends out of operating cash flow; • Paid 32nd consecutive quarterly cash dividend on common shares and declared the next dividend payment of $0.075 per share, payable on December 31, 2021; and • Amended the Company’s Senior Secured Credit Facility (the “Credit Facility) effective November 9, 2021, which increased the borrowing base on the Credit Facility by $20 million, or 67%, to a total borrowing base of $50 million. 17 Table of Contents Overview Oil prices over the past few years have fluctuated widely and been extremely volatile. For example, average daily prices for WTI oil ranged from a high of over $85 per barrel to a low of negative $37 per barrel over the last two years. Although the price of oil per barrel dropped substantially in fiscal 2020 as a result of the impact of the COVID-19 pandemic and geopolitical factors, expectations surrounding improved demand for oil and natural gas combined with restrained supply growth has stimulated a rise in oil and natural gas prices as they averaged approximately $70.57 per barrel of oil and $4.35 per MMBtu of natural gas during the first fiscal quarter of 2022. Worldwide factors such as global health pandemics, geopolitical factors, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, continue to influence prices for oil, natural gas, and NGLs. Local factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, and transportation issues unique to certain producing regions and reservoirs. Oil Net oil production for the Company averaged approximately 1.5 MBOPD during the quarter, a 3% decrease from the prior quarter primarily due to lower Delhi oil production as a result of decreased reservoir pressure due to the suspension of CO 2 purchases from July 15, 2021 through August 20, 2021 for preventative maintenance on the CO 2 purchase pipeline. While the pipeline is under maintenance, the CO 2 recycle facilities continued to operate providing approximately 80% of the historic total injected CO 2 volumes at Delhi. The pipeline is owned and operated by Denbury, and we do not have any ownership in the pipeline which is upstream of the Delhi field. Denbury completed maintenance on the pipeline and resumed flowing CO 2 on August 21, 2021 at the rate of approximately 85 MMcf per day. The decrease in oil production is partially offset by increased Hamilton Dome production due to the partial restoration of previously shut-in wells and strategic adjustments to water injection locations and volumes. Natural Gas Liquids Net NGL production for the Company averaged approximately 1.7 MBOEPD, a 53% increase from the prior quarter. The increase is primarily due to a full quarter of production in the Barnett Shale compared to the 55 production days in the prior quarter from the Barnett Shale Acquisition. Natural Gas Net natural gas production for the Company averaged approximately 16.0 MMCFPD during the quarter, a 52% increase from the prior quarter primarily due to a full quarter of production in the Barnett Shale compared to only 55 production days in the prior fiscal quarter from the Barnett Shale Acquisition. Essentially all of the Company’s natural gas production is generated from the Barnett Shale assets. Net Income The Company recorded quarterly net income of $5.2 million, or $0.16 per share, compared to $2.2 million, or $0.07 per share, in the prior quarter. The increase in the Company's net income is primarily due to the 6% increase in the Company's average realized price per barrel of oil, 14% increase in the Company’s average realized price per barrel of NGLs, and 36% increase in the Company’s average realized price per MMBtu of natural gas. In addition, the Company had an increase of 35% in production volumes from the prior quarter primarily as a result of a full quarter of production from the Barnett Shale compared to only 55 days in the prior quarter. Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.1 of our Form 10-K for the year ended June 30, 2021. Full Cost Pool Ceiling Test and Impairment At September 30, 2021, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if commodity price levels were to substantially decline. Lower commodity prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion, and amortization (“DD&A”) and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted 18 Table of Contents for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test at September 30, 2021 were $57.64 per barrel of oil, $2.97 per MMBtu of gas, and $23.04 per barrel of natural gas liquids. As of September 30, 2021, a 10% decrease in commodity prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties. Impact of the COVID-19 Pandemic and Geopolitical Factors On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States of America declared a national emergency with respect to COVID-19. The virus has continued to spread in the United States of America and abroad. National, state, and local authorities continue to recommend social distancing, impose quarantine and isolation measures. Periodic business closures have impacted large portions of the population as the Delta variant of COVID-19 emerged in the last fiscal year. These measures, while intended to protect human life, are expected to have continued impacts on domestic and foreign economies, potentially resulting in volatility in commodity prices. Currently, none of the Company’s property interests are operated by the Company. As a result, the Company has limited ability to influence or control the operation or future development of such properties. The Company continues to be proactive with its third-party operators to review spending and alter plans as appropriate. The Company is focused on maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home and in the corporate office. The Company has been able to transition the operation of its business with minimal disruption and to maintain its system of internal controls and procedures. Liquidity and Capital Resources At September 30, 2021, the Company had $8.0 million in cash and cash equivalents, compared to $5.3 million of cash and cash equivalents at June 30, 2021. In addition, the Company has a senior secured reserve-based credit facility (the “Senior Secured Credit Facility”) that matures on April 9, 2024. As of September 30, 2021, the Senior Secured Credit Facility had a $30 million borrowing base, with $4 million drawn. Subsequent to the current quarter end, on November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility which increased the Company’s borrowing base to $50 million, of which the Company has elected a maximum commitment amount of $40 million at this time (see Note 18 - Subsequent Events for further discussion). The Senior Secured Credit Facility is subject to a periodic redetermination by the lender based on the value of our oil and natural gas properties and is secured by substantially all of the reserves associated with the Company's assets. Any future borrowings bear interest, at the Company's option, at either the LIBOR plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a current ratio of not less than 1.0 to 1.0, and (iii) a consolidated tangible net worth of not less than $40 million, each as defined in the Senior Secured Credit Facility. The Senior Secured Credit Facility also contains other customary affirmative and negative covenants and events of default. As of September 30, 2021, the Company was in compliance with all covenants contained in the Senior Secured Credit Facility. The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil, natural gas, and natural gas liquids. A portion of these cash flows is used to fund capital expenditures. The Company expects to manage future development activities in the Delhi field and the limited capital maintenance requirements of the Hamilton Dome field and Barnett Shale assets within the boundaries of its operating cash flow and existing working capital. The Company is pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, the Company has access to the undrawn portion of the borrowing base available under its Senior Secured Credit Facility. The Company also has an effective shelf registration statement with the SEC under which the Company may issue up to $500 million of new debt or equity securities. During the three months ended September 30, 2021, the Company funded operations, capital expenditures, and cash dividends with cash generated from operations. As of September 30, 2021, working capital was $15.6 million, an increase of $4.1 million over working capital of $11.5 million at June 30, 2021. This increase in working capital is primarily caused by the increase in revenues during the current fiscal quarter compared to the prior fiscal quarter. 19 Table of Contents The Board of Directors instituted a cash dividend on common stock in December 2013. The Company has since paid 32 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of the Company’s financial strategy, and it is the Company's long-term goal to increase dividends over time, as appropriate. During the industry downturn and global pandemic, effective in the quarter ended June 30, 2020, the Board of Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The reduction in the dividend rate at that time allowed the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a current yield of approximately 3%. Considering improving Company performance and industry outlook, the Board of Directors has since increased the dividend rate three times with the most recent increase occurring on September 9, 2021, when the Board of Directors increased the dividend rate to $0.075 per share effective in the current quarter ended September 30, 2021. As in the past, the Company intends to consider higher dividend levels as warranted by industry conditions and any future accretive acquisitions. Capital Expenditures For the three months ended September 30, 2021, we incurred $0.3 million for Delhi field capital maintenance activities. Based on discussions with operators of the Company's assets, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures, primarily at the Delhi field. Such amounts are not known or approved but we expect such expenditures across all fields to be in the range of $1.0 million to $2.0 million during the remainder of fiscal 2022. Our proved undeveloped reserves at June 30, 2021 included 1.81 MMBOE of reserves and approximately $8.6 million of future development costs associated with Phase V development in the eastern portion of the Delhi Field. Such development requires participation by both the operator and the Company. Based on our discussions with the operator, we do not expect drilling to commence prior to the second half of fiscal 2023. The timing of Phase V is dependent, in part, on the field operator's available funds and capital spending plans and priorities within its portfolio of properties. Funding for our anticipated capital expenditures over the next 12 months is expected to be met from cash flows from operations and current working capital. Cash Flow Activities Cash provided by operating activities in the current fiscal quarter increased $4.4 million compared to the year-ago quarter primarily due to a $13.3 million increase in revenues and decrease in payments paid for derivative settlements of $1.1 million partially offset by a $6.2 million increase in field lease operating expenses with the inclusion of Barnett assets. In addition, there was an increase of $0.7 million in general and administrative expenses primarily due to one-time fees associated with the retirement of the Chief Accounting Officer, additional salary and benefits expense for new employees and professional fees associated with the Barnett Shale acquisition, and a $1.1 million decrease in cash provided from changes in current operating assets and liabilities. The decrease in cash provided from changes in current operating assets and liabilities is primarily driven by a lag in revenue receipts and monthly invoices from the operator of the Barnett Shale assets. Revenue settlement statements from the operator of the Barnett Shale assets and the related cash consideration are generally distributed to the Company two months after production has occurred, which is typical in the industry. Diversified Energy recently acquired the interests and took over as operator of the Barnett Shale assets from Blackbeard. Transition of the operator from Blackbeard to Diversified has caused timing delays in the receipt of revenue and lease operating statements, and as a result, the current fiscal quarter includes additional months of revenue and lease operating expenses related to the Barnett Shale assets. Cash used in investing activities increased $0.2 million primarily due to resumed development costs in the Delhi field after Denbury's emergence from bankruptcy in the prior fiscal year. Cash used in financing activities increased $1.7 million primarily due to an increase in common stock dividends paid in the current quarter as the dividend rate was increased by the Board of Directors to $0.075 per share compared to $0.025 in the year-ago quarter. 20 Table of Contents Results of Operations Three Months Ended September 30, 2021 and 2020 Revenues The following table summarizes total oil, natural gas, and NGL revenues, production volumes, daily production volumes, average realized prices for the three months ended September 30, 2021 and 2020: Three Months Ended September 30, 2021 2020 Variance Variance % Oil and gas production Revenues Oil $ 8,858,463 $ 5,379,161 $ 3,479,302 65 % Natural gas liquids 4,562,218 216,026 4,346,192 2,012 % Natural gas 5,458,329 189 5,458,140 n.m. Total revenues $ 18,879,010 $ 5,595,376 $ 13,283,634 237 % Production volumes Oil (Bbl) 133,929 145,657 (11,728) (8) % Natural gas liquids (Bbl) 157,593 23,724 133,869 564 % Natural gas (Mcf) 1,476,219 130 1,476,089 n.m. Equivalent (BOE) 537,559 169,403 368,156 217 % Daily production volumes Oil (BOPD, net) 1,456 1,583 (127) (8) % Natural gas liquids (BOEPD, net) 1,713 258 1,455 564 % Natural gas (BOEPD, net) 2,674 — 2,674 n.m Equivalent volumes (BOEPD, net) 5,843 1,841 4,002 217 % Realized prices Oil price per Bbl $ 66.14 $ 36.93 $ 29.21 79 % Natural gas liquids price per Bbl 28.95 9.11 19.84 218 % Natural gas price per Mcf 3.70 1.45 2.25 155 % Equivalent price per BOE $ 35.12 (a) $ 33.03 $ 2.09 6 % (a) Equivalent price per BOE has increased only 6% in the current fiscal quarter despite a 79% increase in oil price per Bbl, a 218% increase in NGL price per Bbl, and a 155% increase in natural gas per Mcf. With the Barnett Shale Acquisition, the Company added significant natural gas sales compared to the same year-ago period. Natural gas sales are realized at a significantly lower price per BOE than oil and NGLs which has resulted in only a slight increase in the Company's total weighted average price per BOE. n. m. Not meaningful. Current fiscal quarter total revenues increased 237% primarily due to increased realized commodity prices together with a full quarter of production from the Barnett Shale assets acquired in the prior fiscal quarter. Derivative Contracts Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil prices. The amounts recorded on the unaudited consolidated condensed statements of operations related to derivative contracts represent the (i) (gains) losses related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) (gains) losses on settlements of derivative contracts for positions that have settled or been realized. No positions remain outstanding as of September 30, 2021. 21 Table of Contents Three Months Ended September 30, 2021 2020 Variance Variance % Oil Derivative Contracts Realized loss on derivatives, net $ — $ (1,151,576) $ 1,151,576 (100) % Unrealized gain on derivatives — 816,610 (816,610) (100) % Net loss on derivatives contracts $ — $ (334,966) $ 334,966 (100) % Oil price per Bbl (including impact of realized derivatives) $ 66.14 $ 29.02 Lease Operating Costs Lease operating costs (also referred to as production expenses) are presented in two components: (i) CO 2 purchase costs for the Delhi field and (ii) other lease operating costs for the Delhi, Hamilton Dome, and Barnett Shale fields. Three Months Ended September 30, 2021 2020 Variance Variance % CO 2 costs (a) $ 917,049 $ — $ 917,049 n.m. Other lease operating costs 7,708,118 2,397,924 5,310,194 221 % Total lease operating costs $ 8,625,167 $ 2,397,924 $ 6,227,243 260 % CO 2 costs per BOE $ 1.71 $ — $ 1.71 n.m. All other lease operating costs per BOE 14.34 14.16 0.18 1 % Lease operating costs per BOE $ 16.05 $ 14.16 $ 1.89 13 % (a) Under our contract with the Delhi field operator, purchased CO 2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms. n. m. Not meaningful. Three Months Ended September 30, 2021 2020 Variance Variance % CO 2 costs per mcf $ 0.85 $ — $ 0.85 n.m. CO 2 volumes (MMcf per day, gross) 49.2 — 49.2 n.m. n. m. Not meaningful. CO 2, costs, which solely reflect the cost of purchased CO 2 volumes, increased in the current quarter compared to the year-ago quarter as CO 2 purchases were temporarily suspended throughout the first quarter of fiscal 2021 due to a detected pressure loss in the pipeline that supplies newly purchased CO 2 to the Delhi field. CO 2 purchases historically provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. During the current fiscal quarter, purchases from the pipeline were temporarily suspended from July 15th through August 20th, 2021, while the operator performed preventative maintenance on the pipeline. The pipeline is owned and operated by Denbury, and we do not have any ownership in the pipeline which is upstream of the Delhi field. Compared to the quarter ended September 30, 2020, “Other lease operating costs” increased by $5.3 million primarily due to the Barnett Shale Acquisition on May 7, 2021. The Delhi and Hamilton Dome field’s “Other lease operating costs” were $0.1 million and $0.5 million higher, respectively, compared to the year-ago quarter primarily due to higher workover, labor, and chemical expenses. Delhi field costs per BOE increased 86% to $21.66 per BOE, primarily due to the increase in CO 2 costs compared to the year-ago quarter which had no CO 2 costs, and other lease operating costs per BOE increased by 19% due to higher electricity costs and gas purchases. Also contributing to the increase on a per BOE basis is the 11% decrease in net production volumes in the Delhi field from the year-ago quarter as a result of natural decline and reduced field pressure from the lower CO 2 injections when the CO 2 pipeline was taken offline. 22 Table of Contents Hamilton Dome field costs per BOE increased 55% to $36.23 per BOE in the current quarter as a result of several factors. Higher commodity prices have provided the operator with incentive to perform prior year deferred maintenance and expense workovers that were deemed uneconomic in the year-ago quarter pricing environment, and workover expense has increased 201% compared to the year-ago quarter. This level of make-up workover expense is expected to decline in future quarters. The increase in commodity prices has also caused increases in electricity and fuel costs and ad valorem tax compared to the year-ago quarter. In addition, the increase in commodity prices has resulted in an increase in revenue that is burdened by an increase in the associated production tax compared to the year-ago quarter. Barnett Shale asset costs per BOE were $12.35 in the current quarter. Depletion, Depreciation, and Amortization (“DD&A”) Total DD&A expense was 8% higher compared to the same year-ago quarter primarily due to the increase in production due to the Barnett Shale assets acquired on May 7, 2021. The oil and natural gas DD&A rate per BOE decreased 67% compared to the year-ago quarter primarily as a result of proved oil and natural gas property impairments recorded in fiscal year 2021 and the increase in proved reserves related to the Barnett Shale assets. Three Months Ended September 30, 2021 2020 Variance Variance % DD&A of proved oil and natural gas properties $ 1,425,868 $ 1,362,085 $ 63,783 5 % Depreciation of other property and equipment 1,084 1,810 (726) (40) % Amortization of intangibles — 3,391 (3,391) (100) % Accretion of asset retirement obligations 100,860 43,602 57,258 131 % Total DD&A $ 1,527,812 $ 1,410,888 $ 116,924 8 % Oil and natural gas DD&A rate per BOE $ 2.65 $ 8.04 $ (5.39) (67) % Proved Property Impairment The Company utilizes the full cost method of accounting for its oil and gas properties. Under this method, capitalized costs of oil and natural gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties included in the amortization base, plus the cost of unproved properties excluded from amortization, as adjusted for related income tax effects (the valuation “ceiling”). The prices used in calculating our ceiling test at September 30, 2021 were $57.64 per barrel of oil, $2.97 per MMBtu of gas, and $23.04 per barrel of natural gas liquids compared to $49.72 per barrel of oil, $2.46 per MMBtu of natural gas, and $19.81 per barrel of natural gas liquids at June 30, 2021. There was no proved property impairment recorded in the quarter ended September 30, 2021. The Company recorded a proved property impairment of $9.6 million during the year-ago quarter primarily as a result of the prices used in calculating the ceiling test of $43.63 per barrel of oil and $7.85 per barrel of natural gas liquids (there were no natural gas reserves during the year-ago quarter). General and Administrative Expenses For the three months ended September 30, 2021, general and administrative expenses increased $0.7 million to $1.9 million compared to the year-ago quarter primarily due to one-time fees associated with the retirement of the Chief Accounting Officer, additional salary and benefits expense for new employees, professional fees associated with the Barnett Shale acquisition and some one-time costs associated with the development of the Company’s inaugural Corporate Sustainability Report including a new website and branded matching Investor Relations materials. 23 Table of Contents Other Income and Expenses Other income and expense (net) decreased due primarily to increased interest expense from our outstanding borrowings on the Senior Secured Credit Facility. Three Months Ended September 30, 2021 2020 Variance Variance % Interest and other income $ 2,477 $ 14,426 $ (11,949) (83) % Interest expense (50,612) (22,032) (28,580) 130 % Total other income (expense), net $ (48,135) $ (7,606) $ (40,529) 533 % Net Income (Loss) Net income (loss) attributable to common stockholders for the three months ended September 30, 2021 increased $12.4 million to $5.2 million compared to the same year-ago quarter. Pre-tax income increased due to the aforementioned revenue and expense variances. Our income tax expense increased primarily due to an increase in estimated pre-tax income for the current fiscal year as compared to a pre-tax loss for the prior year period. Three Months Ended September 30, 2021 2020 Variance Variance % Income (loss) before income taxes $ 6,737,987 $ (9,437,326) $ 16,175,313 (171) % Income tax expense (benefit) 1,519,586 (2,302,178) 3,821,764 (166) % Net income (loss) attributable to common stockholders $ 5,218,401 $ (7,135,148) $ 12,353,549 (173) % Income tax expense (benefit) as percentage of income (loss) before income taxes 22.6 % 24.4 % Critical Accounting Policies and Estimates See our Critical Accounting Policies and Estimates as disclosed within Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in the 2021 Form 10-K. For recently adopted and recently issued accounting pronouncements from the Financial Accounting Standards Board, please see Note 2 – Summary of Significant Accounting Policies herein.