AMPY US Equity☆

ITEM 1A.RISK FACTORS

Our business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item 1. Business” of this Annual Report, may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report could have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to the Southern California Pipeline Incident

Significant uncertainties exist regarding the extent and timing of costs and liabilities relating to the Incident, and potential changes in the regulatory and operating environment in which we operate resulting from the Incident may increase the risks to which we are exposed. The duration of such uncertainties may exist for a significant period, and such risks may have a material adverse impact on our business, results of operations and financial condition and the implementation of our strategic agenda. Furthermore, the risks associated with the Incident may heighten the consequences of other risks to which we are exposed, including with respect to access to financing and financial assurance.

37

Table of Contents

Our assumptions and estimates regarding the total aggregate costs associated with the Incident may be inaccurate, which could materially and adversely affect our business, results of operations and financial condition

As of February 2, 2022, the Unified Command announced that response and monitoring efforts have officially concluded for the Beta Incident, and Unified Command would stand down as of such date. We currently estimate that the total costs we have incurred or will incur with respect to the Incident related to (i) actual and projected response and remediation expenses incurred under the direction of the Unified Command and (ii) estimates for certain legal fees to be approximately $90.0 million to $110.0 million. These estimates consider currently available facts and presently enacted laws and regulations. We have made assumptions regarding (i) the probable and estimable amounts expected to be settled with certain vendors for response and remediation expenses and (ii) the resolution of certain third-party claims, excluding claims with respect to losses, which are not probable and reasonably estimable, and (iii) future claims and lawsuits. Our estimates do not include (i) the nature, extent and cost of future legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Incident, (ii) any lost revenue associated with the suspension of operations at Beta, (iii) any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote and (iv) the future costs associated with the permanent repair of the pipeline and the restart of Beta operations. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, settlements with vendors for response and remediation expenses could turn out to be significantly higher or lower than we have estimated. Accordingly, our assumptions and estimates may change in future periods based on future events and total costs may materially increase; therefore, we can provide no assurance that we will not have to accrue significant additional costs in future periods with respect to the Incident.

We are subject to significant litigation and enforcement risk as a result of the Incident.

Under the OPA 90, the Company’s pipeline was designated by the United States Coast Guard as the source of the oil discharge. Therefore, the Company is financially responsible for remediation for certain costs and economic damages as provided in OPA 90. The Company is currently processing covered claims under OPA 90 as expeditiously as possible. At this time, it is not possible to estimate the total number of future claims or the full extent of compensable damages arising from the Incident.

In addition, we and certain of our subsidiaries have been named as defendants in approximately 14 putative class action lawsuits in the United States District Court for the Central District of California. The putative class actions have been consolidated into a single consolidated action in the United States District Court for the Central District of California. In the consolidated action, Plaintiffs filed an amended class action complaint on January 28, 2022. The amended complaint asserted claims against us and MSC Mediterranean Shipping Company, Dordellas Finance Corp., Costamare Shipping Co. S.A., and Capetanissa Maritime Corporation of Liberia. Resolution of the consolidated case may take considerable time, and it is not possible at this time to estimate our potential liability resulting from these actions.

Federal, state and municipal authorities may also take enforcement action against us as a result of the Incident. To date, the U.S. Coast Guard, the U.S. Bureau of Ocean Energy Management, the U.S. Department of Justice, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement, the California Department of Justice, the Orange County District Attorney, the Los Angeles County District Attorney and the California Department of Fish & Wildlife are conducting investigations or examinations of the Incident. Other federal agencies may or have commenced investigations and proceedings, and federal agencies such as the U.S. Environmental Protection Agency may initiate enforcement actions seeking penalties and other relief under the Clean Water Act and other statutes. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil and criminal liability.

On December 15, 2021, a federal grand jury in the Central District of California returned a federal criminal indictment against Amplify Energy Corp., Beta Operating Company, LLC, and San Pedro Bay Pipeline Company in connection with the Incident. The indictment alleges that we committed a misdemeanor violation of the federal Clean Water Act for negligently discharging oil into the contiguous zone of the United States. The United States Attorney’s Office for the Central District of California has stated that its investigation of the Incident and related matters is ongoing. State authorities are conducting parallel criminal investigations as well. We are continuing to cooperate with these federal and state investigations. The outcome of these investigations is uncertain, including whether they will result in additional criminal charges.

38

Table of Contents

Our potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the Incident, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they may have a material adverse impact on our business, results of operations and financial condition and the implementation of our strategic agenda. For further information, please see Note 16, “Commitments and Contingencies — Litigation and Environmental” of the Notes to Consolidated Financial Statements and “Part I — Item 3. Legal Proceedings” included in this Annual Report.

We may be subject to increased permitting obligations and regulatory scrutiny as a result of the Incident.

The Incident may result in more stringent permitting obligations and regulation of our and other oil and gas activities including in federal waters off California and elsewhere, particularly relating to environmental, health and safety protection controls, oversight of oil and gas operations and required financial assurance. Regulatory or legislative action may impact the industry as a whole and could be directed specifically towards operators similarly situated to us. Our ability to obtain the necessary permits to repair the Pipeline and continue operations may be significantly delayed by regulators or such permits could be denied. The California Coastal Commission requested that the Office for Coastal Management of the National Oceanic and Atmospheric Administration approve a Coastal Zone Management Act consistency review of our U.S. Army Corps of Engineers Nationwide Permit 12 application for the proposed permanent repair to the Pipeline. We cannot be certain of the timing or decisions with regard to these permitting obligations and regulations, which could negatively impact our business.

Additionally, new regulations and legislation, as well as evolving practices, may increase the cost of compliance, require changes to our operations and strategic plans and impact our ability to capitalize on our assets.

The Incident may impact our ability to access financing on acceptable terms and may materially impact our liquidity.

The reputational consequences of the Incident, ongoing concerns surrounding costs arising from the Incident, ongoing contingencies related to the Incident and the impact of the Incident on our liquidity and financial performance could increase our financing costs and limit our access to financing on acceptable terms. Our ability to engage in trading activities may also be impacted due to counterparty concerns about our financial and business risk profile following the Incident. Such counterparties may require that we provide collateral or other forms of financial security for their obligations. Certain counterparties for our non-trading businesses may also require that we provide collateral for certain contractual obligations.

In addition, we may be unable to access liquidity under our Revolving Credit Facility in the event there are pending or threatened legal, arbitration or administrative proceedings which, if determined adversely, might reasonably be expected to have a material adverse effect on our ability to meet the payment obligations under our Revolving Credit Facility. Extended constraints on our ability to obtain financing and to engage in trading activities on acceptable terms (or at all) may put pressure on our liquidity. In addition, this could occur at a time when cash flows from our business operations may be constrained. In order to address severe liquidity constraints, we could be required to further reduce capital expenditures, sell strategic assets or obtain financing on terms that could have a significant adverse effect on stockholder returns and the implementation of our strategic plans.

We may not have adequate insurance to compensate us, and our insurers may not pay particular claims.

We currently maintain insurance that covers against certain losses and expenses associated with the Incident. However, we cannot guarantee that our insurance policies will cover all losses that we incur in connection with the Incident or that disputes over insurance claims will not arise with our insurance carriers. Additionally, the insurers may not pay particular claims or may take an extended period of time to do so. In addition, our insurance policies are subject to limitations and exclusions, which may increase our costs or lower our revenues, thereby possibly having a material adverse effect on our business, results of operations and financial condition. Finally, we cannot guarantee that we will be able to renew our insurance policies on the same or commercially reasonable terms, or at all, in the future.

39

Table of Contents

The shut-in of the pipeline could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.

Our production depends, in part, upon our assets that are capable of commercial production not being shut-in (i.e., suspended from production). In response to the Incident, we have shut-in the pipeline impacted by the Incident and the Beta field, which has decreased our overall production volumes. This decrease in production will impact our ability to generate cash flows from operations, and we will experience a reduction in our available liquidity, which may adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs. Additionally, in part due to permitting obligations and regulations discussed in this Annual Report, we cannot be certain whether and when, if at all, we will be able to restart operations at the Beta field.

The Incident has created significant risk to our reputation and has diverted, and will continue to divert, the attention of our management team.

The Incident has damaged our reputation, which may have a long-term impact on us. Adverse public, political and industry sentiment towards us, and oil and gas activities generally, could damage or impair our existing commercial relationships with counterparties, partners and governmental agencies and could impair our access to debt or capital, new investment opportunities, operatorships or other essential commercial arrangements with potential partners and governmental agencies. In addition, responding to the Incident may place a significant burden on our cash flow, which could also impede our ability to invest in new opportunities and deliver long-term growth.

In addition, our response to the Incident has required significant management focus. Key management and operating personnel are, and will need to continue, devoting substantial attention to responding to the Incident and to addressing the associated consequences for us, leaving them less time to devote to executing our strategic plans. In addition, we rely on recruiting and retaining high-quality employees to execute our strategic plans and to operate our business. The Incident response has placed significant demands on our employees, and the reputational damage suffered by us as a result of the Incident and any consequent adverse impact on our business could affect employee recruitment, productivity, retention and the results of our operations.

Risks Related to Our Business

Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.

Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:

● the regional, domestic and foreign supply of oil, natural gas and NGLs;

● the level of commodity prices and expectations about future commodity prices;

● the level of global oil and natural gas exploration and production;

● the cost of exploring for developing, producing and transporting reserves;

● the price and quantity of foreign imports;

40

Table of Contents

● speculative trading in crude oil and natural gas derivative contracts;

● the level of consumer product demand;

● weather conditions and other natural disasters;

● risks associated with operating drilling rigs;

● domestic and foreign governmental regulations and taxes;

● the impact of energy conservation efforts;

● overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2021, the NYMEX-WTI oil future price ranged from a high of $84.65 per Bbl to a low of $(37.63) per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.20 per MMBtu to a low of $1.48 per MMBtu. For the year ended December 31, 2021, the WTI posted prices ranged from a high of $84.65 per Bbl on October 26, 2021 to a low of $47.62 per Bbl on January 4, 2021 and NYMEX-Henry Hub natural gas market price ranged from a high of $6.20 per MMBtu on October 27, 2021 to a low of $2.45 per MMBtu on January 22, 2021. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have sustained depressed realized prices during this period and are generally correlated with the price of oil. A further or extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition.

If commodity prices decline and/or remain depressed for a prolonged period, a significant portion of our development projects may become uneconomic and result in write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to fund our operations.

Oil, natural gas and NGL prices have experienced significant volatility over the past few years. An extended decline in commodity prices could render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to fund our operations.

No impairment expense was recognized for the year ended December 31, 2021, and we recognized $477.0 million in impairment expense for the year ended December 31, 2020. An extended decline in commodity prices may cause us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our Revolving Credit Facility.

A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.

The global or national outbreak of an infectious disease, such as COVID-19 or emerging variants, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, and (v) restrictions that we and our contractors and subcontractors impose, including curtailment or shutting in of production, to ensure the safety of employees and others. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.

41

Table of Contents

Further, COVID-19 or emerging variants may adversely impact the supply chain for equipment or services needed for our operations, including as a result of mandatory shutdowns and other pandemic-related measures implemented in locations where such equipment or services are manufactured or distributed. We may also be impacted by significant disruptions to the operations of our logistics and service providers.

Loss of our key executive officers or other key personnel, or an inability to attract and retain such officers and personnel, could negatively affect our business.

Our future success depends on the skills, experience and efforts of our key executive officers. The sudden loss of any of these executives’ services or our failure to appropriately plan for any expected key executive succession could materially and adversely affect our business and prospects, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. Additionally, we also depend on our ability to attract and retain qualified personnel to operate and expand our business. If we fail to attract or retain talented new employees, our business and results of operations could be negatively affected. Workers may choose to pursue employment with our competitors or in other fields; this competition has become exacerbated by the increase in employee resignations currently taking place throughout the United States as a result of the COVID-19 pandemic, which is commonly referred to as the “great resignation.”

We may be unable to maintain compliance with the covenants in the Revolving Credit Facility, which could result in an event of default thereunder that, if not cured or waived, would have a material adverse effect on our business and financial condition.

Under our Revolving Credit Facility, we are required to maintain (i) as of the date of determination, a maximum total debt to EBITDAX ratio of 4.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) maintain a minimum hedging requirement to at least 30%-60% of our estimated production from total proved developed producing reserves. If we were to violate any of the covenants under our Revolving Credit Facility and were unable to obtain a waiver or amendment, it would be considered a default after the expiration of any applicable grace period. If we were in default under our Revolving Credit Facility, then the lenders may exercise certain remedies including, among others, declaring all borrowings outstanding thereunder, if any, immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due, because we might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Revolving Credit Facility are secured by mortgages on not less than 90% of the PV-9 value of our oil and gas properties (and at least 90% of the PV-9 value of the proved, developed and producing oil and gas properties), and if we are unable to repay our indebtedness under our Revolving Credit Facility, the lenders could seek to foreclose on our assets.

Restrictive covenants in our Revolving Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Restrictive covenants in our Revolving Credit Facility impose significant operating and financial restrictions on us and our subsidiaries. These restrictions limit our ability to, among other things:

● incur additional liens;

● incur additional indebtedness;

● merge, consolidate or sell our assets;

● pay dividends or make other distributions or repurchase or redeem our stock;

● make certain investments; and

● enter into transactions with our affiliates.

42

Table of Contents

Our Revolving Credit Facility also requires us to comply with certain financial maintenance covenants as discussed above. A breach of any of these covenants could result in a default under our Revolving Credit Facility. If a default occurs and remains uncured or unwaived, the administrative agent or majority lenders under our Revolving Credit Facility may elect to declare all borrowings outstanding thereunder, if any, together with accrued interest and other fees, to be immediately due and payable. The administrative agent or majority lenders under our Revolving Credit Facility would also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay our indebtedness when due or declared due, the administrative agent will also have the right to proceed against the collateral pledged to it to secure the indebtedness under our Revolving Credit Facility. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.

We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants in our Revolving Credit Facility. The terms and conditions of our Revolving Credit Facility affect us in several ways, including:

● limiting management’s discretion in operating our business.

Our lenders periodically redetermine the amount we may borrow under our Revolving Credit Facility, which may materially impact our operations.

Our Revolving Credit Facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Accordingly, declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute on our business plans. Any reduction in the borrowing base would materially and adversely affect our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations. In addition, as hedges roll off, the borrowing base is subject to further reduction. Our Revolving Credit Facility requires us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of notice to do so. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the Revolving Credit Facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under our Revolving Credit Facility.

43

Table of Contents

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Revolving Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.

We intend to maintain a portfolio of commodity derivative contracts covering at least 30% - 60% of our estimated production from proved developed producing reserves over a one-to-three-year period at any given point in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations, at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil, natural gas and NGL prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could significantly reduce our cash flow and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, our California oil typically has a lower gravity, and a portion has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil requires more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. These discounts, if significant, could reduce our cash flows and adversely affect our results of operations and financial condition.

Our estimated reserves and future production rates are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

In order to prepare our estimates, we must project production rates and timing of operating and development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.

The process also requires economic assumptions about matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds.

Actual future production, oil prices, natural gas prices, revenues, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of development, existing commodity prices and other factors, many of which are beyond our control.

44

Table of Contents

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves shown in this report, or standardized measure, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the FASB, we base the estimated discounted future net cash flows from our proved reserves on the trailing 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements, which is required by the SEC and FASB, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

The failure to replace our proved oil and natural gas reserves could adversely affect our business, financial condition, results of operations, production and cash flows.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and, production and therefore, our cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would materially and adversely affect our business, financial condition and results of operations.

If we reduce our capital spending in an effort to conserve cash, this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flow from operations and income. Further, if the borrowing base under our Revolving Credit Facility decreases, or our revenues decrease, as a result of lower oil or natural gas prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash flows.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then-realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of our development and production activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our development and production operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

● unusual or unexpected geological formations;

● unexpected operational events and conditions;

● failure of down hole equipment and tubulars;

45

Table of Contents

● loss of wellbore mechanical integrity;

● title problems;

● loss of drilling fluid circulation;

● hydrocarbon or oilfield chemical spills;

● fires, blowouts, surface craterings and explosions;

● adverse weather conditions and natural disasters.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations are delayed or canceled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition and results of operations may be adversely affected. If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our business, financial condition, results of operations and cash flows.

Expenses not covered by our insurance could have a material adverse effect on our financial position and results of operations.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, all of which could cause substantial financial losses. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The location of any properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of potential damages resulting from these risks. The occurrence of any of these or other similar events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, suspension or disruption of operations, substantial revenue losses and repairs to resume operations.

We maintain insurance coverage against potential losses that we believe is customary in the industry. However, insurance against all operational risk is not available to us. These insurance policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A liability, claim or other loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash flows. For a discussion of the risks surrounding insurance associated with the Incident, see “— We may not have adequate insurance to compensate us, and our insurers may not pay particular claims.”

46

Table of Contents

The production from our Wyoming Bairoil properties could be adversely affected by the cessation or interruption of the supply of CO2 to those properties.

We inject water and CO2 into formations on substantially all of the Wyoming Bairoil properties to increase production of oil and natural gas. The additional production and reserves attributable to the use of enhanced recovery methods are inherently difficult to predict. If we are unable to produce oil and gas by injecting CO2 in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected. Additionally, our ability to utilize CO2 to enhance production is subject to our ability to obtain sufficient quantities of CO2. If, under our CO2 supply contracts, the supplier is unable to deliver its contractually required quantities of CO2 to us, or if our ability to access adequate supplies is impeded, then we may not have sufficient CO2 to produce oil and natural gas in the manner or to the extent that we anticipate, and our future oil and gas production volumes will be negatively impacted.

Many of our properties are in areas that may have been partially depleted or drained by offset wells.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further exploit and develop our reserves.

Our expectations for future development activities are planned to be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. We cannot predict in advance of drilling, testing and analysis of data whether any particular drilling location will yield production in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Our ability to drill, recomplete and develop locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure and lease expirations. Because of these uncertainties, we cannot be certain of the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition, results of operations and cash flows.

Part of our strategy may involve using horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations may involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we may face while drilling horizontal wells include, but are not limited to, the following:

● landing our wellbore in the desired drilling zone;

● running our casing the entire length of the wellbore; and

Risks that we may face while completing wells include, but are not limited to, the following:

47

Table of Contents

If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.

Our potential use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and we could incur losses as a result of such expenditures. As a result, future drilling activities may not be successful or economical, which could have a material adverse impact on our financial condition, results of operations and cash flows.

SEC rules could limit our ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and will likely continue to limit our ability to book additional PUDs, especially in a time of depressed commodity prices. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.

Our industry is cyclical, and historically there have been periodic shortages of rigs, equipment, supplies and crew. Sustained declines in oil and natural gas prices may reduce the number of service providers for such rigs, equipment, supplies and crews, contributing to or resulting in shortages. Alternatively, during periods of higher oil and natural gas prices, the demand for rigs, equipment, supplies and crews is increased and can lead to shortages of, and increasing costs for, development equipment, supplies, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict the Company’s ability to drill the wells and conduct the operations that it currently has planned relating to the fields where our properties are located. In addition, some of our operations require supply materials for production, such as CO2, which could become subject to shortages and increased costs. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and impact our development plan, which would thus affect our financial conduction, results of operations and our cash flows.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Development and production of oil and natural gas in offshore waters have inherent and historically higher risk than similar activities onshore.

Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than our other oil and natural gas activities. We are vulnerable to the risks associated with operating offshore California, including risks relating to:

48

Table of Contents

● oil field service costs and availability;

● compliance with environmental and other laws and regulations;

● third-party marine vessels, including situations similar to the Incident;

● failure of equipment or facilities.

In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because significant portions of our offshore operations are conducted in environmentally sensitive areas, including areas with significant residential populations and public and commercial infrastructure. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of remediating a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be subject to regulatory scrutiny and liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

Adverse developments in our operating areas could adversely affect our business, financial condition, results of operations and cash flows.

Our properties are located in the Rockies, federal waters offshore Southern California, East Texas / North Louisiana, Oklahoma and Eagle Ford. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, could adversely affect our business, financial condition, results of operations and cash flows.

We are dependent upon a small number of significant customers for a substantial portion of our production sales. The loss of those customers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition and results of operations.

We had three customers that each accounted for 10% or more of total reported revenues for the year ended December 31, 2021. The loss of these customers or any significant customer, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. Also, if any significant customer reduces the volume it purchases from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, and our revenues and cash flows could decline. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production. See “Item 1. Business — Operations — Marketing and Major Customers.”

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

We are subject to credit risk due to concentration of our oil and natural gas receivables. The inability or failure of our significant customers, or any purchasers of our production, to meet their payment obligations to us or their insolvency or liquidation could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and cash flows.

49

Table of Contents

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors and other counterparties. Some of our vendors and other counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors and other counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’ and other counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors and/or counterparties could adversely affect our business, financial condition, results of operations and cash flows.

Conservation measures, technological advances and increasing public attention to climate change and environmental matters could reduce demand for oil and natural gas and have an adverse effect on our business, financial condition and reputation.

Fuel conservation measures, alternative fuel requirements, incentives to conserve energy or use alternative energy sources, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Such initiatives or related activism aimed at limiting climate change and reducing air pollution, as well as negative investor sentiment toward our industry and the impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, cash flows, and ability to access capital. Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change, may also lead to increased litigation risk and regulatory, legislative, and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business. In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance or have caused other redressable injuries under federal and/or state common law. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations. Moreover, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities.

We may be unable to compete effectively with larger companies.

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis and many of our competitors have access to capital at a lower cost than that available to us. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition, results of operations and cash flows.

50

Table of Contents

Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. For example, our ability to produce and sell oil from the Beta Properties will depend on the availability of the pipeline infrastructure between platforms as well as the San Pedro Bay Pipeline for delivery of that oil to shore, and any unavailability of that pipeline infrastructure or pipeline could cause us to shut in all or a portion of the production from the Beta Properties for the length of such unavailability. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business, financial condition, results of operations and cash flows.

We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for and the development, production and transportation of oil and natural gas. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. In addition, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment. Thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

51

Table of Contents

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. New laws and regulations continue to be enacted, particularly at the state level, and, under the Biden Administration, the long-term trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted, or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Further, the Mineral Leasing Act of 1920, as amended (the “Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. state or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. It is possible that our stockholders may be citizens of foreign countries who do not own their stock in a U.S. corporation, or that even if such stock are held through a U.S. corporation, their country of citizenship may be determined to be non-reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the more significant laws and regulations that affect us.

Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs, could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. In addition, the EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. However, the United States House of Representatives passed H.R. 5376, known as the Build Back Better Act on November 3, 2021. The House version of the bill targets methane from oil and gas sources by proposing to implement fees for excess methane leaking from wells, storage sites and pipelines as well as fees for new producing and non-producing oil and gases leases and off-shore pipelines. In the absence of such federal climate legislation, almost one-half of the states have taken legal measures to reduce emissions of GHGs, including through the planned development of GHG emission inventories and/or regional GHGs cap and trade programs. In addition, on an international level, the United States was one of nearly 200 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emission reduction goals beginning in 2020. However, the United States formally announced its intent to withdraw from the Paris Agreement in November 2019, which became effective in November 2020. On January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which will become effective on February 19, 2021. In addition, various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

52

Table of Contents

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. For example, such effects could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, increases in our costs of operation or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations — Regulation of “Greenhouse Gas” Emissions for a description of the climate change laws and regulations that affect us.

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.

The ESA and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. The listing of species in areas where we operate or, alternatively, entry into certain range-wide conservation planning agreements could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely for gathering and transportation services could impact the availability of those services. Any potential impact to the availability of gathering and transportation services could impact our ability to market and sell our production, which could have a material adverse effect on our business, financial condition and results of operations. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely for gathering and transportation services.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water and the disposal of waste, including produced water and drilling fluids. Restrictions on the ability to obtain water or dispose of waste may impact our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our development and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The Clean Water Act imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into “waters of the United States.” Permits must be obtained to discharge pollutants to such waters and to conduct construction activities in such waters, which include certain wetlands. The Clean Water Act and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and

53

Table of Contents

other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells, and the disposal and recycling of produced water, drilling fluids, and other wastes, may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In some jurisdictions, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity or resulted in stricter regulatory requirements relating to the location and operation of underground injection wells. For example, we conduct oil and gas drilling and production operations in the Mississippian Lime formation in Oklahoma, a high-water play, which requires us to dispose of large volumes of saltwater generated as part of our operations. In 2015, the Oklahoma Geological Survey attributed an increase in seismic activity in Oklahoma to saltwater disposal wells in the Arbuckle formation. Around the same time, the OCC, whose Oil and Gas Conservation Division regulates oil and gas operations in Oklahoma, began issuing regulations targeting saltwater disposal activities in certain areas of interest within the Arbuckle formation. The regulations include operational requirements (i.e., mechanical integrity testing of wells permitted for disposal of 20,000 or more barrels of water per day, daily monitoring and recording of well pressure and discharge volume), as well as orders to shut-in wells, reduce well depths, or decrease disposal volumes. Under these regulations, in 2016 and 2017, the OCC ordered us to limit the volume of saltwater disposed of in saltwater disposal wells in the Arbuckle formation and established caps for ten of our saltwater disposal wells in February 2017, which caps are still in place. To ensure that we had an adequate number of wells for disposal, we secured permits for additional saltwater disposal wells outside of the Arbuckle formation. We timely satisfied all OCC saltwater disposal requirements, while maintaining our production base without any negative material impact. However, any additional orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations — Water Discharges and Other Waste Discharges & Spills” and “— Hydraulic Fracturing” for an additional description of the laws and regulations relating to the discharge of water and other wastes and hydraulic fracturing that affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic fracturing techniques in our drilling and completion programs. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. See “Item 1. Business — Environmental, Health and Safety Matters and Regulations — Hydraulic Fracturing” for a description of the federal and state legislative and regulatory initiatives relating to hydraulic fracturing that affect us.

If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of prohibitions, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes further regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

The cost of decommissioning is uncertain.

We are required to maintain reserve funds to provide for the payment of decommissioning costs associated with the Beta Properties. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.

54

Table of Contents

We may be required to post cash collateral pursuant to our agreements with sureties under our existing or future bonding arrangements, which may have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.

Pursuant to the terms of our existing bonding arrangements with various sureties in connection with the decommissioning obligations related to our Beta Properties, or under any future bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the sureties’ sole discretion. If additional collateral is required to support surety bond obligations, this collateral would probably be in the form of cash or letters of credit, certificate of deposit or other similar forms of liquid collateral. We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for future bonds.

We entered into two escrow funding agreements with certain of our surety providers to fund interest-bearing escrow accounts to reimburse and indemnify the surety providers for any claims arising under the surety bonds related to the decommissioning of our Beta properties. If we fail to comply with our obligations under such escrow agreements, the surety providers may request additional collateral in the form of cash or letters of credit, certificates of deposit or other similar forms of liquid collateral. If we are required to provide additional collateral pursuant to any such request or otherwise, our liquidity position may be negatively impacted, and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures in the current year or future years, may be unable to execute our asset retirement obligation plan or may be unable to comply with our existing debt instruments. If we are unable or unwilling to provide additional collateral, we may have to pursue alternate bonding arrangements with other sureties. See Note 6, “Asset Retirement Obligations” and Note 16, “Commitments and Contingencies — Supplemental Bond for Decommissioning Liabilities Trust Agreement” of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements and Supplementary Data, in this Annual Report for additional information.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged by the Tax Act, Congress could consider and could include some or all of these proposals as part of future tax reform legislation. It is unclear whether any of the foregoing or similar proposals will be considered and enacted as part of future tax reform legislation and if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development and any such change could have an adverse effect on the Company’s financial position, results of operations and cash flows.

55

Table of Contents

Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.

As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 2.PROPERTIES

Information regarding our properties is contained in “Item 1. Business — Our Areas of Operation” and “—Our Oil and Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” contained herein.

ITEM 3.LEGAL PROCEEDINGS

Proceedings and Investigations relating to the Southern California Pipeline Incident

Amplify Energy Corp., Beta Operating Company, LLC d/b/a Beta Offshore, and San Pedro Bay Pipeline Company have been named as defendants in approximately 14 putative class action lawsuits related to the Incident and filed in the United States District Court for the Central District of California. On December 20, 2021 the putative class actions were consolidated into a single consolidated action in the United States District Court for the Central District of California. In the consolidated action, Plaintiffs filed an amended class action complaint on January 28, 2022. The amended complaint asserts claims against us for (1) Violations of the Lempert-Keene-Seastrand Oil Spill Prevention and Response Act, Gov. Code §8670, et seq.; (2) Lost Profits and Earning Capacity Damages (Federal Oil Pollution Act of 1990, §§ 1002, 1006); (3) Strict Liability for Ultrahazardous Activities; (4) Negligence; (5) Public Nuisance; (6) Negligent Interference with Prospective Economic Advantage; (7) Trespass; (8) Continuing Private Nuisance; and (9) Violations of California’s Unfair Competition Law (Cal. Bus. & Prof.Code §§ 17200, et seq.). The proposed classes are: (1) a class made up of persons or entities that owned or worked on a commercial fishing vessel, or sold commercial seafood, in the affected area; (2) owners or lessees of residential waterfront properties or residential properties with a private easement to the beach in the affected areas; and (3) persons or entities that owned or worked in certain waterfront tourism industries in the allegedly affected area. The amended complaint also asserts claims against MSC Mediterranean Shipping Company, Dordellas Finance Corp., Costamare Shipping Co. S.A., and Capetanissa Maritime Corporation of Liberia. The Company denies the allegations made against it and intends to vigorously defend against them. The parties are engaged in discovery and the Court has tentatively set trial for September 2023.

Under the Oil Pollution Act of 1990, 33 U.S.C. S 2701 et seq. (“OPA 90”), our pipeline was designated by the United States Coast Guard as the source of the oil discharge and therefore we are financially responsible for remediation and for certain costs and economic damages as provided for in OPA 90, as well as certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages. We are currently processing covered claims under OPA 90 as expeditiously as possible.

56

Table of Contents

On February 28, 2022, we filed a third-party complaint in the United States District Court for the Central District of California against MSC Mediterranean Shipping Company, Dordellas Finance Corporation, Costamare Shipping Co. S.A., Capetanissa Maritime Corporation of Liberia, V.Ships Greece Ltd., the vessels MSC Danit and COSCO Beijing, those vessels’ as-yet unknown captains and crews, and the Marine Exchange of Los Angeles-Long Beach Harbor d/b/a Marine Exchange of Southern California for damages and injunctive relief. Our complaint alleges that the actions and inactions of these parties caused and continue to cause Amplify significant harm and, without them, the Incident never would have happened. We seek contribution from these parties under OPA, damages for the harm caused to us, and injunctive relief requiring the Marine Exchange of Southern California to alert us and any other owners of undersea property of any and all potential anchor-dragging incidents in the area surrounding their undersea property within 24 hours of the incident and to not allow vessels to anchor in the anchorages located immediately adjacent to the Pipeline when heavy weather is likely. We may, in the future, seek contribution from any other third parties that are liable or potentially liable under OPA or any other law in connection with the Incident.

On February 28, 2022, we also filed a motion to dismiss certain claims from the plaintiffs’ consolidated amended class action complaint in the United States District Court of the Central District of California. The motion seeks dismissal of the state law claims against Amplify because they are preempted by OPA or otherwise fail as a matter of law. The motion also asks the Court to enforce OPA by dismissing the claims of those plaintiffs who have not yet complied with OPA’s requirements.

We are currently subject to a number of ongoing investigations related to the Incident by certain federal and state agencies. To date, the U.S. Coast Guard, the U.S. Bureau of Ocean Energy Management, the U.S. Department of Justice, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement, the California Department of Justice, the Orange County District Attorney, the Los Angeles County District Attorney, and the California Department of Fish & Wildlife are conducting investigations or examinations of the Incident. Other federal agencies may or have commenced investigations and proceedings, and federal agencies such as the U.S. Environmental Protection Agency may initiate enforcement actions seeking penalties and other relief under the Clean Water Act and other statutes. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil and criminal liability.

On December 15, 2021, a federal grand jury in the Central District of California returned a federal criminal indictment against Amplify Energy Corp., Beta Operating Company, LLC, and San Pedro Bay Pipeline Company in connection with the Incident. The indictment alleges that we committed a misdemeanor violation of the federal Clean Water Act for negligently discharging oil into the contiguous zone of the United States. The United States Attorney’s Office for the Central District of California has stated that its investigation of the Incident and related matters is ongoing. State authorities are conducting parallel criminal investigations as well. We are continuing to cooperate with these federal and state investigations. The outcome of these investigations is uncertain, including whether they will result in additional criminal charges.

Our potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the Incident, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they may have a material adverse impact on our business, results of operations and financial condition and the implementation of our strategic agenda.

Other Legal Proceedings

As part of our normal business activities, we may be named as defendants in other litigation and legal proceedings, including those arising from regulatory and environmental matters. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We are not aware of any other litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows. No amounts have been accrued at December 31, 2021, in regard to our litigation and legal proceedings.

For additional information regarding legal proceedings, see Note 16, “Commitments and Contingencies — Litigation and Environmental” of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report and “Part II – Item 1A. Risk Factors — Risks Related to the Southern California Pipeline Incident” which are incorporated herein by reference.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

​

57

Table of Contents

PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our Common Stock is listed on the NYSE under the trading symbol “AMPY” and has been trading since August 7, 2019.

As of February 28, 2022, we had 38,064,214 shares of our Common Stock outstanding. As of February 28, 2022, we had twenty-seven record holders of our Common Stock, based on information provided by our transfer agent.

Dividends Policy

While we may decide to pay cash dividends in the future, we have not paid, nor do we currently intend to pay, any cash dividends on our common stock. Future dividends, if any, are subject to debt covenants under our Revolving Credit Facility and discretionary approval by the board of directors.

Securities Authorized for Issuance Under Equity Compensation Plan

See the information incorporated by reference in “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” for information regarding shares of our common stock authorized for issuance under our stock compensation plans, which information is incorporated herein by reference.

Issuer Purchases of Equity Securities

The following sets forth information with respect to the Company’s repurchases of shares of its Common Stock during the fourth quarter of 2021.

​

​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ ​ ​ ​ Total Number of Approximate Dollar

​ ​ ​ ​ ​ ​ Shares Purchased as Value of Shares That

​ ​ ​ ​ ​ ​ Part of Publicly May Yet Be

​ Total Number of Average Price Announced Plans Purchased Under the

Period Shares Purchased Paid per Share or Programs Plans or Programs (1)

​ ​ ​ ​ ​ ​ ​ ​ (In thousands)

Common Shares Repurchased (1) ​

ITEM 6.Reserved

​

​

58

Table of Contents

ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis (“MD&A”) of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” contained herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I, Item 1A. of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of this Annual Report.

Overview

We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on the reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties located in Oklahoma, the Rockies (Bairoil), federal waters offshore Southern California (Beta), East Texas/North Louisiana and Eagle Ford (Non-Op). Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs.

Production and Operation Update

Our oil, natural gas and NGL production for the fiscal year 2021 decreased 14%, 13% and 17%, respectively from 2020. The decrease in production was attributable to Beta properties being shut in due to pipeline incident and natural decline. We had a 67% increase in oil and natural gas sales which was from higher realized oil, natural gas and NGL prices offset by lower production changes.

Our total estimated proved reserves increased to 121.2 MMBoe in 2021 compared to 113.8 MMBoe in 2020.

As of December 31, 2021, we are the operator of record for properties containing 92% of our total estimated proved reserves.

Impact of COVID-19

For a discussion of how COVID-19 has affected and may continue to affect our business and financial condition, see the discussion under the heading “Industry Trends” in Part I, Item 1 of this report, as well as the Risk Factors set forth in Part I, Item 1A of this report.

Recent Developments

Southern California Pipeline Incident

On October 2, 2021, contractors operating under the direction of Beta Operating Company, LLC (“Beta”), one of our subsidiaries, observed an oil sheen on the water approximately four miles off the coast of Newport Beach, California (the “Incident”). Beta platform personnel were notified and promptly initiated our Oil Spill Response Plan, which was reviewed and approved by the Bureau of Safety and Environmental Enforcement’s Oil Spill Preparedness Division within the United States Department of the Interior, and which included the required notifications of specified regulatory agencies. On October 3, 2021, a Unified Command, consisting of the Company, the U.S. Coast Guard and California Department of Fish and Wildlife’s Office of Spill Prevention and Response, was established to respond to the Incident.

59

Table of Contents

On October 5, 2021, the Unified Command announced that reports from its contracted commercial divers and Remotely Operated Vehicle footage indicated that a 4,000-foot section of our pipeline had been displaced with a maximum lateral movement of approximately 105 feet and that the pipeline had a 13-inch split, running parallel to the pipe. On October 14, 2021, the U.S. Coast Guard announced that it had a high degree of confidence the size of the release was approximately 588 barrels of oil, which was below the previously reported maximum estimate of 3,134 barrels. On October 16, 2021, the U.S. Coast Guard announced that it had identified the Mediterranean Shipping Company (DANIT) as a “vessel of interest” and its owner Dordellas Finance Corporation and operator Mediterranean Shipping Company, S.A. as parties in interest in connection with an anchor-dragging incident in January 2021 (the “Anchor Dragging Incident”), which occurred in close proximity to our pipeline, and that additional vessels of interest continue to be investigated. On November 19, 2021, the U.S. Coast Guard announced that it had identified the COSCO (Beijing) as another vessel involved in the Anchor Dragging Incident and named its owner Capetanissa Maritime Corporation of Liberia and its operator V.Ships Greece Ltd. as parties in interest. The cause, timing and details regarding the Incident are currently under investigation and any information regarding the Incident is preliminary.

At the height of the Incident response, we deployed over 1,800 personnel working under the guidance and at the direction of the Unified Command to aid in cleanup operations. As of October 14, 2021, all beaches that had been closed following the Incident have reopened. On February 2, 2022, the Unified Command announced that response and monitoring efforts have officially concluded for the Incident, and Unified Command would stand down as of such date. Amplify is grateful to our Unified Command partners for their collaboration and professionalism over the course of the response.

In response to the Incident, all operations have been suspended and the pipeline has been shut-in until we receive the required regulatory approvals to begin operations. On October 4, 2021, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), Office of Pipeline Safety (“OPS”) issued a Corrective Action Order (“CAO”) pursuant to 49 U.S.C. § 60112, which makes clear that no restart of the affected pipeline may occur until PHMSA has approved a written restart plan. The California Coastal Commission has requested approval from the Office of Coastal Management for the National Oceanic and Atmospheric Association to conduct a Coastal Zone Management Act consistency review of the U.S. Army Corps of Engineers Nationwide Permit (“NWP”) 12 application for the proposed permanent repair permit. We are working expeditiously and cooperatively to comply with the requirements of the relevant agencies in order to gain such approvals and any other regulatory approvals that are necessary to permanently repair the pipeline and restart operations. As a result of the uncertainties related to the permitting and regulatory approval process, we can provide no assurances as to whether and when, if at all, we will be able to restart operations at the Beta field. At present no operations are underway in the Beta field.

We are currently subject to a number of ongoing investigations related to the Incident by certain federal and state agencies. To date, the U.S. Coast Guard, the U.S. Bureau of Ocean Energy Management, the U.S. Department of Justice, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement, the California Department of Justice, the Orange County District Attorney, the Los Angeles County District Attorney, and the California Department of Fish & Wildlife are conducting investigations or examinations of the Incident. Other federal agencies may or have commenced investigations and proceedings, and federal agencies such as the U.S. Environmental Protection Agency may initiate enforcement actions seeking penalties and other relief under the Clean Water Act and other statutes. Amplify continues to comply with all regulatory requirements and investigations. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil and criminal liability.

On December 15, 2021, a federal grand jury in the Central District of California returned a federal criminal indictment against Amplify Energy Corp., Beta Operating Company, LLC, and San Pedro Bay Pipeline Company in connection with the Incident. The indictment alleges that we committed a misdemeanor violation of the federal Clean Water Act for negligently discharging oil into the contiguous zone of the United States. The United States Attorney’s Office for the Central District of California has stated that its investigation of the Incident and related matters is ongoing. State authorities are conducting parallel criminal investigations as well. We are continuing to cooperate with these federal and state investigations. The outcome of these investigations is uncertain, including whether they will result in additional criminal charges.

60

Table of Contents

We and certain of our subsidiaries have been named as defendants in approximately 14 putative class action lawsuits, which have been consolidated into a single consolidated action in the United States District Court for the Central District of California. In the consolidated action, Plaintiffs filed an amended class action complaint on January 28, 2022. The amended complaint asserted claims against us and MSC Mediterranean Shipping Company, Dordellas Finance Corp., Costamare Shipping Co. S.A., and Capetanissa Maritime Corporation of Liberia. Resolution of the consolidated case may take considerable time, and it is not possible at this time to estimate our potential liability resulting from these actions. For additional discussion of the legal proceedings associated with the Incident, see “Part I — Item 3. Legal Proceedings,” “Part II — Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part III — Item 1A. Risk Factors — Risks Related to the Southern California Pipeline Incident.”

Under the Oil Pollution Act of 1990, 33 U.S.C. S 2701 et seq. (“OPA 90”), our pipeline was designated by the U.S. Coast Guard as the source of the oil discharge and therefore we are financially responsible for remediation and for certain costs and economic damages as provided for in OPA 90, as well as certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages. We are currently processing covered claims under OPA 90 as expeditiously as possible. In addition, the Natural Resource Damage Assessment remains ongoing and therefore the extent, timing and cost of related to such assessment are difficult to project. While we anticipate insurance will reimburse us for expenses related to the Natural Resource Damage Assessment, any potentially uncovered expenses may be material and could impact our business, our and results of operations and could put pressure on our liquidity position going forward.

We currently estimate that the total costs we have incurred or will incur with respect to the Incident related to (i) actual and projected response and remediation expenses incurred under the direction of the Unified Command and (ii) estimates for certain legal fees, to be approximately $90.0 million to $110.0 million. These estimates consider currently available facts and presently enacted laws and regulations. We have made assumptions regarding (i) the probable and estimable amounts expected to be settled with certain vendors for response and remediation expenses and (ii) the resolution of certain third-party claims, excluding claims with respect to losses, which are not probable and reasonably estimable, and (iii) future claims and lawsuits. Our estimates do not include (i) the nature, extent and cost of future legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Incident, (ii) any lost revenue associated with the suspension of operations at Beta, (iii) any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote and (iv) the future costs associated with the permanent repair of the pipeline and the restart of the Beta operations. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, settlements with vendors for response and remediation expenses could turn out to be significantly higher or lower than we have estimated. Accordingly, our assumptions and estimates may change in future periods based on future events and total costs may materially increase; therefore, we can provide no assurance that we will not have to accrue significant additional costs in future periods with respect to the Incident.

In accordance with customary insurance practice, we maintain insurance policies, including loss of production income insurance, against many potential losses or liabilities arising from our operations and at costs that we believe to be economic. We regularly review our risk of loss and the cost and availability of insurance and revise our insurance accordingly. Our insurance does not cover every potential risk associated with our operations and is subject to certain exclusions and deductibles. While we expect our insurance policies will cover a material portion of the total aggregate costs associated with the Incident, including but not limited to response and remediation expenses, defense costs and loss of revenue resulting from suspended operations, we can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses related to the Incident and such view and understanding is preliminary and subject to change.

As of December 31, 2021, the Company has incurred total aggregate gross costs of $99.0 million, of which the Company has received or believes that it is probable that it will receive $97.4 million in insurance recoveries. The Company’s net charge of $1.6 million, which is classified as “Pipeline Incident Loss” in the Company’s Consolidated Statements of Operations, insurance deductibles and legal costs incurred to date that are not currently expected to be recovered under an insurance policy.

Through December 31, 2021, we had collected $48.3 million out of the approximate $97.4 million of costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of December 31, 2021, we have recognized a receivable of approximately $49.1 million for the portion of costs that we believe is probable of recovery from insurance, net of deductibles and amounts collected during 2021. Subsequent to December 31, 2021, for the period January 1, 2022 through March 1, 2022, we received insurance cost recoveries of $22.1 million

61

Table of Contents

Additionally, during 2021, we recognized $6.7 million related to approved LOPI insurance claims, which is classified as “Other Revenues” in the Company’s Consolidated Statement of Operations. Subsequent to December 31, 2021, for the period January 1, 2022 through March 1, 2022, we received the entire LOPI insurance claim settlement of $6.7 million. For additional discussion of the risks associated with the Incident, see “Item 1A. Risk Factors — Risks Related to the Southern California Pipeline Incident.”

Business Environment and Operational Focus

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production; (iii) cash settlements on our commodity derivatives; (iv) lease operating expense; (v) gathering, processing and transportation; (vi) general and administrative expense; and (vii) Adjusted EBITDA.

Production Volumes

Production volumes directly impact our results of operations. For more information about our volumes, see “— Results of Operations” below.

Realized Prices on the Sale of Oil and Natural Gas

We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, realized prices are heavily influenced by product quality and location relative to consuming and refining markets.

Natural Gas. The NYMEX-Henry Hub future price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas can differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO2 and other inert content by volume. Natural gas with a high Btu content (“wet” natural gas) sells at a premium to natural gas with low Btu content (“dry” natural gas) because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost required to separate the sulfur and CO2 from the natural gas to render it marketable. Wet natural gas may be processed in third-party natural gas plants, where residue natural gas as well as NGLs are recovered and sold. At the wellhead, our natural gas production typically has an average energy content greater than 1,000 Btu. The dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the produced natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Historically, these index prices have generally been at a discount to NYMEX-Henry Hub natural gas prices.

Oil. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The ICE Brent futures price is a widely used global price benchmark for oil. The actual prices realized from the sale of oil can differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s American Petroleum Institute (“API”) gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil).

Location differentials result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential).

62

Table of Contents

The oil produced from our onshore properties is a combination of sweet and sour oil, varying by location. This oil is typically sold at the NYMEX-WTI price, adjusted for quality and transportation differential, depending primarily on location and purchaser. The oil produced from our Beta Properties is heavy and sour oil. Oil produced from our Beta Properties is currently sold based on refiners’ posted prices for California Midway-Sunset deliveries in Southern California, adjusted primarily for quality and a negotiated market differential.

Price Volatility. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. The following table shows the low and high commodity future index prices for the periods indicated:

​

​ ​ ​ ​ ​ ​ ​

​ High Low

For the Year Ended December 31, 2021: ​ ​

NYMEX-WTI oil future price range per Bbl ​ $ 84.65 ​ $ 47.62

NYMEX-Henry Hub natural gas future price range per MMBtu ​ $ 6.20 ​ $ 2.45

ICE Brent oil future price range per Bbl ​ $ 86.40 ​ $ 51.80

​ ​ ​ ​ ​ ​ ​

For the Five Years Ended December 31, 2021: ​ ​

NYMEX-WTI oil future price range per Bbl ​ $ 84.65 ​ $ (37.63)

NYMEX-Henry Hub natural gas future price range per MMBtu ​ $ 6.20 ​ $ 1.48

ICE Brent oil future price range per Bbl ​ $ 86.40 ​ $ 19.33

​

Commodity Derivative Contracts. Our hedging activities are intended to support oil, natural gas and NGL prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 30% - 60% of our estimated production from proved developed producing reserves over a one-to-three-year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Principal Components of Cost Structure

63

Table of Contents

Outlook

Based on our current plans, our capital expenditure program for the full year 2022 is expected to be approximately $20.0 million to $30.0 million. The charts below detail the allocation of capital across our asset base and by investment type based on the midpoint of our 2022 capital expenditure range.

​

As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices and other factors. We anticipate funding our 2022 capital program from internally generated cash flow, borrowings under our Revolving Credit Facility and/or debt or equity financings may provide incremental financial flexibility.

Critical Accounting Policies and Estimates

The methods, estimates and judgments we use in applying our critical accounting policies have a significant impact on the results we report in our Consolidated Financial Statements. We evaluate our estimates and judgments on an on-going basis. We base our estimates on historical experience and on assumptions that we believe to be reasonable under the circumstances. Our experience and assumptions form the basis for our judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may vary from what we anticipate and different assumptions or estimates about the future could change our reported results. Within the context of these critical accounting policies, we are not currently aware of any reasonably likely event that would result in materially different amounts being reported.

Oil and Natural Gas Properties.We use the successful efforts method of accounting for our oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. See Note 2 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for a discussion of the fair value measurements of our proved and unproved oil and natural gas properties and other long-lived assets.

64

Table of Contents

We believe accounting for oil, natural gas, and NGLs properties is a critical accounting estimate because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries. Significant changes in these estimates could result in the costs of our proved and unproved properties not being recoverable; therefore, we would be required to recognize an impairment.

Oil and Natural Gas Reserves. Proved oil and natural gas reserves are estimated in accordance with the rules established by the SEC and FASB. The rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalation in future years except by contractual arrangements. Our reserve estimates are prepared by our reserve engineers and audited by independent engineers.

Our reserve estimates are updated at least annually using geological and reserve data, as well as production performance data. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates, while decreases in recoverable economic volumes generally increase per unit depletion rates. A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimate may impact the outcome of our assessment of oil and natural gas producing properties for impairment. We cannot predict what reserve revisions may be required in future periods.

We believe oil and natural gas reserves is a critical accounting estimate because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations for any period could be materially affected by changes in our assumptions. Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense.

Fair Value Estimates. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3).

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. See Notes 4 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for a discussion of our fair value measurements.

We believe fair value estimates are a critical accounting estimate because the significance of a particular input to fair value measurements requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Significant uses of fair value measurements include: derivative instruments, asset retirement obligations (“ARO”), and impairment assessments of long-lived assets.

The carrying values of our cash and cash equivalents (Level 1), accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2021 and 2020.

Our commodity derivative financial instruments are used to reduce the impact of natural gas and oil price fluctuations. We record our derivative instrument in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings as we have not elected hedge accounting for any of our derivative positions. Significant changes to the market value of derivative instruments due to the volatility of oil and natural gas prices can have an impact on our financial condition and results of operations.

65

Table of Contents

The fair value of our AROs (Level 3) are based on discounted cash flow projections which uses numerous estimates and assumptions, and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, credit-adjusted risk-free rate and inflation rates.

We review our assets for impairments annually or when events and circumstances indicate the carrying value of our properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production or drilling results, higher operating and development costs, or lower commodity prices. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Revenue Recognition. Our revenue is primarily derived from the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the reporting organization satisfies a performance obligation.

Prices for natural gas, NGLs and oil sales are negotiated based on factors normally considered in the industry, such as index or spot price, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties must be estimated.

We believe revenue recognition is a critical accounting estimate because revenue is an essential portion of our results of operations.

Contingencies and Insurance Accounting. A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.

Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.

An insurance receivable is recognized when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between the insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

We believe contingencies and insurance accounting is a critical accounting estimate because we must assess the probability of the loss related to the contingency and the expected amount that is covered by insurance. At December 31, 2021, we are not aware of any regulatory demands, fines or penalties of any dollar amount.

Results of Operations

The results of operations for the years ended December 31, 2021 and 2020, have been derived from our Consolidated Financial Statements.

66

Table of Contents

The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

​

​ ​ ​ ​ ​ ​ ​

​ ​ For the Year Ended

​ ​ December 31,

​ ​ ($ In thousands)

Gathering, processing and transportation ​ 20,807 ​ 20,547

Depreciation, depletion and amortization ​ 28,068 ​ 40,268

Impairment expense ​ — ​ 476,936

General and administrative expense ​ 25,285 ​ 27,789

Accretion of asset retirement obligations ​ 6,611 ​ 6,206

Loss (gain) on commodity derivative instruments ​ 142,439 ​ (60,671)

Gain on extinguishment of debt ​ 5,516 ​ —

​ ​ ​ ​ ​ ​ ​

Oil and natural gas revenues: ​ ​

​ ​ ​ ​ ​ ​ ​

Production volumes: ​ ​

Average net production (MBoe/d) ​ 24.0 ​ 27.8

​ ​ ​ ​ ​ ​ ​

Average realized sales price (excluding commodity derivatives): ​ ​

Natural gas (per Mcf) ​ 3.46 ​ 1.55

​ ​ ​ ​ ​ ​ ​

Average unit costs per Boe: ​ ​

Lease operating expense ​ $ 13.88 ​ $ 11.75

Gathering, processing and transportation ​ 2.38 ​ 2.02

Taxes other than income ​ 2.54 ​ 1.27

General and administrative expense ​ 2.89 ​ 2.73

Depletion, depreciation and amortization ​ 3.21 ​ 3.95

​

For the year ended December 31, 2021 compared to the year ended December 31, 2020

Net losses of $32.1 million and $464.0 million was recorded for the year ended December 31, 2021 and 2020, respectively.

67

Table of Contents

Oil, natural gas and NGL revenues were $335.8 million and $200.9 million for the year ended December 31, 2021 and 2020, respectively. Average net production volumes were approximately 24.0 MBoe/d and 27.8 MBoe/d for the year ended December 31, 2021 and 2020, respectively. The change in production volumes was primarily due to natural decline, Beta properties shut-in starting in October 2021 and the impact of Winter Storm Uri that caused a severe freeze in areas where we operate, including Texas, Oklahoma and Louisiana, resulting in shut-ins for wells, pipelines and plants for approximately two weeks in February 2021. The average realized sales price was $38.39 per Boe and $19.71 per Boe for the year ended December 31, 2021 and 2020, respectively. The change in the average realized sales price was primarily due to the increase in realized commodity prices. Commodity prices were depressed in 2020 due to the impact of the pandemic and the effects of OPEC production related to supply and demand decisions.

Other revenues were $7.1 million and $1.3 million for the year ended December 31, 2021 and 2020, respectively. The change in other revenues was primarily related to us receiving loss of production income insurance of $6.7 million for the period of November 15, 2021 through December 31, 2021.

Lease operating expense was $121.4 million and $119.7 million for the year ended December 31, 2021 and 2020, respectively. The change in lease operating expense was primarily related to an increase for 2021 workover projects compared to 2020, partially offset by the employee retention credit received of $2.0 million for the first and second quarters of 2021. On a per Boe basis, lease operating expense was $13.88 and $11.75 for the year ended December 31, 2021 and 2020, respectively. The change in lease operating expense on a per Boe basis was primarily related to slightly higher costs and lower production.

Gathering, processing and transportation expenses were $20.8 million and $20.5 million for the year ended December 31, 2021 and 2020, respectively. The change in gathering, processing and transportation expenses was primarily driven by the decrease in production in the first quarter of 2021 from Winter Storm Uri, partially offset by additional fees from our non-operated wells and by fee increases from our processing plants and minimum volume commitments. On a per Boe basis, gathering, processing and transportation expenses were $2.38 and $2.02 for the year ended December 31, 2021 and 2020, respectively.

Taxes other than income was $22.3 million and $12.9 million for the year ended December 31, 2021 and 2020, respectively. The change in taxes other than income is due to an increase in production taxes as a result of the increase in commodity prices. On a per Boe basis, taxes other than income were $2.54 and $1.27 for the year ended December 31, 2021 and 2020, respectively. The change in taxes other than income on a per Boe basis was primarily due to an increase in commodity prices.

DD&A expense was $28.1 million and $40.3 million for the year ended December 31, 2021 and 2020, respectively. The change in DD&A expense was primarily due to a 14% decrease in production and a 19% decrease in our DD&A rate.

Impairment expense. No impairment expense was recorded for the year ended December 31, 2021. We recorded an impairment expense of $476.9 million for the year ended December 31, 2020. We recognized $427.6 million of impairment expense on proved properties for the year ended December 31, 2020. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. We recognized $49.3 million of impairment expense on unproved properties for the year ended December 31, 2020, which was related to expiring leases and the evaluation of qualitative and quantitative factors related to the current decline in commodity prices.

General and administrative expense was $25.3 million and $27.8 million for the year ended December 31, 2021 and 2020, respectively. The change in general and administrative expense is primarily related to (i) the employee retention credit received of $0.8 million for the first and second quarters of 2021; (ii) a decrease in professional services of $1.0 million, and (iii) a decrease in legal services of $0.8 million, offset with an increase of $1.2 million in stock compensation expense.

Net losses (gains) on commodity derivative instruments of $142.4 million were recognized for the year ended December 31, 2021, consisting of a $54.1 million decrease in the fair value of open positions and $88.3 million of cash settlements paid on expired positions. Net gains on commodity derivative instruments of $60.7 million were recognized for the year ended December 31, 2020, consisting of a $19.7 million decrease in the fair value of open positions offset by $62.4 million of cash settlements received on expired positions and $18.0 million of cash settlements received on terminated positions.

68

Table of Contents

Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

Interest expense, net was $12.1 million and $20.5 million for the year ended December 31, 2021 and 2020, respectively. The change in interest expense is related to being in a gain position for interest rate swaps of $0.2 million for the year ended December 31, 2021 compared to being in a loss position of $4.0 million for the year ended December 31, 2020. Additionally, we had a decrease of $2.6 million in the amortization and write-off of deferred financing costs and a decrease of $1.4 million in interest expense due to lower outstanding borrowings.

Average outstanding borrowings under our Revolving Credit Facility were $240.2 million and $279.1 million for the year ended December 31, 2021 and 2020, respectively.

Gain on extinguishment of debt was $5.5 million for the year ended December 31, 2021, which is related to the forgiveness of the PPP Loan. See Note 8 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash flow from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

● Income tax expense;

● DD&A;

● Accretion of asset retirement obligations (“AROs”);

● Loss on commodity derivative instruments;

● Cash settlements received on expired commodity derivative instruments;

● Losses on sale of assets and other, net;

● Share-based compensation expenses;

● Exploration costs;

● Acquisition and divestiture related expenses;

● Amortization of gain associated with terminated commodity derivatives;

69

Table of Contents

● Restructuring related costs;

● Reorganization items, net;

● Severance payments;

● Bad debt expense; and

● Other non-routine items that we deem appropriate.

Less:

● Interest income;

● Income tax benefit;

● Gain on extinguishment of debt

● Gain on expired commodity derivative instruments;

● Cash settlements paid on expired commodity derivative instruments;

● Gains on sale of assets and other, net; and

● Other non-routine items that we deem appropriate.

We are required to comply with certain Adjusted EBITDA-related metrics under our Revolving Credit Facility.

We believe that Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.

Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow, develop existing reserves or acquire additional oil and natural gas properties.

The following tables presents a reconciliation of the Company’s net income (loss) and cash flows operating activities to Adjusted EBITDA, our most directly comparable GAAP financial measures, for each of the periods indicated.

70

Table of Contents

Reconciliation of Net Income (Loss) to Adjusted EBITDA

​

​ ​ ​ ​ ​ ​ ​

​ For the Year Ended

​ December 31,

​ (In thousands)

Impairment expense ​ — ​ 476,936

Losses (gains) on commodity derivative instruments ​ 142,439 ​ (60,671)

Share-based compensation expense ​ 1,612 ​ (177)

Gain on extinguishment of debt ​ (5,516) ​ —

Pipeline incident loss ​ 1,599 ​ —

Income tax expense ​ — ​ 115

Acquisition and divestiture related expenses ​ 19 ​ 1,092

Exploration costs ​ 57 ​ 56

Loss on settlement of AROs ​ 11 ​ 250

Bad debt expense ​ 95 ​ 294

Non-cash inventory valuation adjustment ​ — ​ 1,003

Secondary offering expenses ​ — ​ 311

Reorganization items, net ​ ​ 6 ​ ​ 566

Severance payments ​ ​ — ​ ​ 57

​

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

​

​ ​ ​ ​ ​ ​ ​

​ ​ For the Year Ended

​ ​ December 31,

​ ​ (In thousands)

Net cash provided by operating activities ​ $ 62,969 ​ $ 74,330

Gain (loss) on interest rate swaps ​ 217 ​ (4,044)

Cash settlements paid (received) on interest rate swaps ​ 1,912 ​ 1,254

Cash settlements paid (received) on terminated derivatives ​ — ​ (17,977)

Pipeline incident loss ​ 1,599 ​ —

Amortization and write-off of deferred financing fees ​ (626) ​ (3,272)

Acquisition and divestiture related expenses ​ 19 ​ 1,092

Income tax expense - current portion ​ — ​ 115

Exploration costs ​ 57 ​ 56

Plugging and abandonment cost ​ 307 ​ 577

Reorganization items, net ​ 6 ​ 566

Severance payments ​ — ​ 57

Non-cash inventory valuation adjustment ​ — ​ 1,003

​

71

Table of Contents

Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our Revolving Credit Facility, and equity and debt capital markets. As we pursue reserve and production growth, we plan to monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our Revolving Credit Facility will provide us with the financial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2022 development activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. We anticipate funding our 2022 capital program from internally generated cash flow, borrowings under our Revolving Credit Facility and/or debt or equity financings may provide incremental financial flexibility.

Impact of the Southern California Pipeline Incident. There is substantial uncertainty surrounding the full impact that the Incident will have on our financial condition and cash flow generation going forward. We have incurred and will continue to incur costs as a result of the Incident, and we anticipate that the suspension of production from Beta will lead to a material reduction in revenue from these assets. Although we carry customary insurance policies, including loss of production income insurance, which we expect will cover a material portion of the total aggregate costs associated with the Incident, including loss of revenue resulting from suspended operations, we can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses related to the Incident.

Capital Markets. We do not currently anticipate any near-term capital markets activity, but we will continue to evaluate the availability of public debt and equity for funding potential future growth projects and acquisition activity.