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.
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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.
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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
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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).
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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
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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.
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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.
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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.
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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.
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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.
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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;
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● 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.
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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
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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.
Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL and natural gas 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 total 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 amount. 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.
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could also result in losses.
Capital Expenditures. Our total capital expenditures were approximately $30.9 million for the year ended December 31, 2021, which were primarily related to capital workovers and capital facilities expenditures located in the Rockies, Oklahoma and California and non-operated drilling activity in Eagle Ford.
Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable as well as the classification of our debt outstanding. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.
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As of December 31, 2021, we had a working capital deficit of $39.4 million primarily as the result of (i) a short-term derivative liability balance of $53.1 million (ii) an accrued liabilities balance of $57.8 million (iii) an accounts payable balance of $33.8 million, and (iv) a revenue payable balance of $20.4 million, less (i) an accounts receivable balance of $92.0 million, (ii) prepaid expenses and other current assets balance of $15.0 million and (iii) a cash balance of $18.8 million.
Debt Agreements
Revolving Credit Facility. On November 2, 2018, OLLC as borrower, entered into the Revolving Credit Facility (as amended and supplemented to date) with Bank of Montreal, as administrative agent. At December 31, 2021, our borrowing base under our Revolving Credit Facility was subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report. The borrowing base as of December 31, 2021, was $245.0 million.
As of December 31, 2021, we were in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with our Revolving Credit Facility.
As of December 31, 2021, we had approximately $15.0 million of available borrowings under our Revolving Credit Facility.
On November 10, 2021, we completed our scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under our Revolving Credit Facility was reaffirmed at $245.0 million; provided that, beginning on February 28, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month until the next regularly scheduled redetermination, which is expected to occur in April 2022. This impact on our borrowing base may limit our liquidity position and may impact our ability to finance our operations.
On June 16, 2021, we completed our scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under our Revolving Credit Facility was decreased from $260.0 million to $245.0 million. Additionally, the administrative agent under our Revolving Credit Facility was changed from Bank of Montreal to KeyBank.
For additional information regarding our Revolving Credit Facility, 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.
COVID-19 Relief Funding. On June 22, 2021, we were notified by the bank that our PPP Loan was approved for full and complete forgiveness by the Small Business Association. For the year ended December 31, 2021, we recorded a gain on extinguishment of debt for $5.5 million in our Consolidated Statements of Operations.
Under the Consolidated Appropriations Act 2021 passed by the U.S. Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified, making us eligible for the employee retention credit subject to meeting certain criteria. We met the criteria for the first and second quarters of 2021 and recognized a $2.8 million employee retention credit during the year ended December 31, 2021, which is included as a credit to general and administrative expense and to lease operating expense in our Consolidated Statements of Operations.
Material Cash Requirements
Contractual commitments. We have contractual commitments under our debt agreements, including interest payments and principal payments. 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.
Lease Obligations. We have operating leases for office and warehouse spaces, office equipment, compressors and surface rentals related to our business obligations. As of December 31, 2021, our future commitments under these contracts were $5.3 million in 2022, $1.2 million in 2023, $1.5 million in 2024, $1.5 million in 2025, $1.5 million in 2026 and $4.1 million thereafter. See Note 12 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.
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Sinking fund payments. We have a funding requirement to fund a trust account to comply with supplemental regulatory bonding requirements related to our decommissioning obligations for our offshore Southern California production facilities. As of December 31, 2021, our future commitment under this agreement were $6.7 million in 2022, $8.0 million in 2023, $15.8 million in years 2024, $15.8 million in years 2025, $15.8 million in years 2026 and $110.5 million thereafter. See Note 16 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the years ended December 31, 2021 and 2020, have been derived from our Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.
For the Year Ended
December 31,
(In thousands)
Net cash provided by operating activities $ 62,969 $ 74,330
Net cash used in investing activities (29,428) (35,890)
Net cash used in financing activities (25,106) (28,401)
For the year ended December 31, 2021 compared to the year ended December 31, 2020
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $63.0 million and $74.3 million for the year ended December 31, 2021 and 2020, respectively. Production volumes decreased to 24.0 MBoe/d in 2021 from 27.8 MBoe/d in 2020 and the average realized sales price increased to $38.39 per Boe in 2021 from $19.71 per Boe in 2020. The changes in production and average realized sales price were primarily related to decreased drilling activities and increased commodity prices.
Net cash provided by operating activities for the year ended December 31, 2021 included $90.2 million of cash paid on expired derivative instruments compared to $61.1 million of cash receipts on expired derivative instruments and $18.0 million of cash receipts on terminated derivative instruments for the year ended December 31, 2020. For the year ended December 31, 2021, we had net losses on commodity derivative instruments of $142.4 million compared to net gains of $60.7 million for the year ended December 31, 2020.
In addition, we recorded a $5.5 million gain on extinguishment of debt related to the forgiveness of the PPP Loan. See Note 8 of the Notes to the Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding the PPP Loan.
Investing Activities. Net cash used in investing activities for the year ended December 31, 2021 was $29.4 million, of which $29.3 million was used for additions to oil and gas properties. Net cash used in investing activities for the year ended December 31, 2020, was $35.9 million, of which $34.8 million was used for additions to oil and gas properties.
Financing Activities. We had net repayments of $25.0 million and $30.0 million under our Revolving Credit Facility for the year ended December 31, 2021 and 2020, respectively.
We received a $5.5 million loan under the Paycheck Protection Program on April 24, 2020. As noted above, we received complete forgiveness for the PPP loan received.
We paid out dividends of $3.8 million on March 30, 2020 to stockholders on record at the close of business on March 16, 2020. The board of directors subsequently suspended quarterly dividends. Future dividends, if any, are subject to debt covenants under our Revolving Credit Facility and discretionary approval by the board of directors.
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For the year ended December 31, 2020 compared to the year ended December 31, 2019
Information related to the comparison of our discussion of the cash flows for the year ended December 31, 2020 compared to the year ended December 31, 2019, is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” of our 2020 Form 10-K filed with the SEC and is incorporated by reference into this Annual Report on Form 10-K.
Capital Requirements
See “— Outlook” for additional information regarding our capital spending program for 2022.
Recently Issued Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this Annual Report and are incorporated herein by reference.
None.
ITEM 9A.CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures.
As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of the Company, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of the Company, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon this evaluation, the principal executive officer and principal financial officer of the Company have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2021.
Management’s Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
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Under the supervision and with the participation of the Company’s management, including the principal executive officer and principal financial officer of the Company, the Company assessed the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this assessment, the Company’s management, including its principal executive and financial officers, concluded that the Company’s internal control over financial reporting was effective as of December 31, 2021 based on the criteria set forth under the COSO Framework.
Deloitte & Touche LLP, the independent registered public accounting firm who audited the Company’s Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” in this Annual Report, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021, is contained herein under the heading “Report of Independent Registered Public Accounting Firm.”
Changes in Internal Controls Over Financial Reporting
No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits 31.1 and 31.2 to this Annual Report.
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Report of Independent Registered Public Accounting Firm
The Stockholders and Board of Directors
Amplify Energy Corp.:
Opinion on Internal Control Over Financial Reporting
We have audited the internal control over financial reporting of Amplify Energy Corp. and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Company and our report dated March 9, 2022, expressed an unqualified opinion on those financial statements and financial statement schedule.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 9, 2022
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ITEM 9B.OTHER INFORMATION
In consultation with the compensation committee’s independent compensation consultant, the compensation committee reviewed our executive officers’ compensation packages and approved adjustments for the following executive officers on March 7, 2022: (i) Martyn Willsher’s annual base salary increased to $500,000 (from $350,000); (ii) Jason McGlynn’s annual base salary increased to $350,000 (from $290,000); (iii) Tony Lopez’s annual base salary increased to $310,000 (from $270,000) and his discretionary bonus compensation target percentage increased to 70% of annual base salary (from 60% of annual base salary); and (iv) Eric Willis’s discretionary bonus compensation target percentage increased to 70% of annual base salary (from 65% of annual base salary).
ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None
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PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement relating to the 2022 Annual Meeting of Stockholders of Amplify Energy Corp. (the “Proxy Statement”) to be held on May 17, 2022.
The Company’s Code of Business Conduct and Ethics (the “Code of Ethics”) can be found on the Company’s website located at http://investor.amplifyenergy.com/corporate-governance. Any stockholder may request a printed copy of the Code of Ethics by submitting a written request to the Company’s Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.
ITEM 11.EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to the Proxy Statement.
The information required by this item is incorporated herein by reference to the Proxy Statement.
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated herein by reference to the Proxy Statement.
ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated herein by reference to the Proxy Statement.
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PART IV
ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
Our Consolidated Financial Statements are included under Part II, “Item 8. Financial Statements and Supplementary Data” of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” on page F-1 of this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
The exhibits listed on the Exhibit Index below are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.
Exhibit Index
ExhibitNumber Description
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ExhibitNumber Description
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ExhibitNumber Description
21.1* — List of Subsidiaries of Amplify Energy Corp.
23.1* — Consent of Cawley, Gillespie and Associates, Inc.
23.2* — Consent of Deloitte & Touche LLP
99.1* — Report of Cawley, Gillespie and Associates, Inc.
101.INS* — Inline XBRL Instance Document
101.SCH* — Inline XBRL Schema Document
101.CAL* — Inline XBRL Calculation Linkbase Document
101.DEF* — Inline XBRL Definition Linkbase Document
101.LAB* — Inline XBRL Labels Linkbase Document
101.PRE* — Inline XBRL Presentation Linkbase Document
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ExhibitNumber Description
* Filed or furnished as an exhibit to this Annual Report on Form 10-K.
# Management contract or compensatory plan or arrangement.
ITEM 16.Form 10-K Summary
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Amplify Energy Corp.
(Registrant)
Date: March 9, 2022 By: /s/ Jason McGlynn
Name: Jason McGlynn
Title: Senior Vice President and Chief Financial Officer
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.
Name Title (Position with Amplify Energy Corp.) Date
/s/ Martyn Willsher President and Chief Executive Officer March 9, 2022
Martyn Willsher (Principal Executive Officer)
Jason McGlynn (Principal Financial Officer)
/s/ Eric Dulany Vice President and Chief Accounting Officer March 9, 2022
Eric Dulany (Principal Accounting Officer)
/s/ Christopher W. Hamm Chairman and Director March 9, 2022
Christopher W. Hamm
/s/ Patrice Douglas Director March 9, 2022
Patrice Douglas
/s/ Randal T. Klein Director March 9, 2022
Randal T. Klein
/s/ Todd R. Snyder Director March 9, 2022
Todd R. Snyder
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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
AMPLIFY ENERGY CORP.
INDEX TO FINANCIAL STATEMENTS
Page No.
Report of Independent Registered Public Accounting Firm (PCAOB ID 34) F-2
Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020 F-5
Notes to Consolidated Financial Statements F-9
Note 1 – Organization and Basis of Presentation F-9
Note 2 – Summary of Significant Accounting Policies F-10
Note 3 – Revenues F-15
Note 4 – Fair Value Measurements of Financial Instruments F-16
Note 5 – Risk Management and Derivative Instruments F-18
Note 6 – Asset Retirement Obligations F-21
Note 7 – Restricted Investments F-21
Note 8 – Debt F-21
Note 9 – Equity (Deficit) F-25
Note 10 – Earnings per Share F-26
Note 11 – Equity-based Awards F-26
Note 12 – Leases F-30
Note 14 – Related Party Transactions F-32
Note 15 – Southern California Pipeline Incident F-33
Note 16 – Commitments and Contingencies F-35
Note 17 – Income Tax F-37
Note 18 – Supplemental Oil and Gas Information (Unaudited) F-40
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Amplify Energy Corp.:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Amplify Energy Corp. and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of operations, stockholders’ equity, and cash flows, for each of the two years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2022, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Oil and Gas Reserve Quantities & Related Undiscounted Cashflows as used in the calculation of DD&A and Impairment — Refer to Notes 2 and 18 to the financial statements
Critical Audit Matter Description
The Company’s proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and natural gas reserves related to the associated field. The development of the Company’s oil and natural gas reserve quantities require management to make significant estimates and assumptions. The Company engages an independent reservoir engineer, management’s specialist, to estimate oil and natural gas quantities using generally accepted methods, calculation procedures and engineering data. Changes in assumptions or engineering data could have a significant impact on the amount of depletion. Proved oil and natural gas properties were $319.1 million as of December 31, 2021, Depreciation Depletion and Amortization expense was $28.1 million and impairment expense was $0 for the year then ended.
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Given the significant judgments made by management and management’s specialist, performing audit procedures to evaluate the Company’s oil and natural gas reserve quantities, including management’s estimates and assumptions related to oil, gas, and NGL prices require a high degree of auditor judgment and an increased extent of effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s significant judgments and assumptions related to oil and natural gas reserves included the following, among others:
We evaluated the reasonableness of oil, gas, and NGL prices by comparing such amounts to:
● Third party industry sources
● Historical realized oil, gas, and NGL prices
● Historical realized oil, gas, and NGL price differentials
With the assistance of our fair value specialists, we evaluated management’s estimated future oil, gas, and NGL prices and escalation rates by performing the following:
Southern California Pipeline Incident – Refer to Notes 2, 13 and 15 to the financial statements
Critical Audit Matter Description
The Company has estimated the total aggregate cost with respect to the oil spill off the coast of Newport Beach, California which occurred on October 2, 2021, for (i) actual and projected response and remediation expenses incurred under the direction of the Unified Command. The aggregate costs as estimated are accrued in the consolidated financial statements. The Company also recognizes an insurance receivable when collection of the receivable is deemed probable. The Company has recognized a total liability of $98.8 million as of December 31, 2021. Accrued liabilities – pipeline incident was $34.4 million as of December 31, 2021. Insurance receivables – pipeline incident was $55.8 million. Through December 31, 2021, the Company had collected $48.3 million, net of deductible.
Given the significant judgements made by management, performing audit procedures to evaluate the Company’s accrued liabilities – pipeline incident and insurance receivable – pipeline incident, require an increased extent of effort and a need to involve our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s significant judgements and assumptions related to the recognition of costs for the spill and associated insurance receivables included the following, among others:
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● We evaluated the estimated total aggregated costs by performing the following:
◾ Direct confirmation with legal advisors
● We evaluated the insurance receivable by performing the following:
● Vouched the receipt of reimbursements
● Compared amounts received to amounts reimbursed from insurance providers
◾ Obtained credit ratings for insurance underwriters
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 9, 2022
We have served as the Company’s auditor since 2020.
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AMPLIFY ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In thousands, except outstanding shares)
December 31, December 31,
ASSETS
Current assets:
Prepaid expenses and other current assets 15,018 15,572
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method 799,532 775,167
Accumulated depreciation, depletion and amortization (634,212) (609,231)
Long-term derivative instruments — 873
Operating lease - long term right-of-use asset 2,716 2,500
LIABILITIES AND EQUITY
Current liabilities:
Short-term derivative instruments 53,144 10,824
Long-term derivative instruments 9,664 847
Operating lease liability 2,017 266
Commitments and contingencies (see Note 16)
Stockholders' equity (deficit):
See Accompanying Notes to Consolidated Financial Statements.
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AMPLIFY ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Year Ended
December 31,
Revenues:
Costs and expenses:
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)
Pipeline incident loss 1,599 —
Other (expense) income:
Gain on extinguishment of debt 5,516 —
Inventory valuation adjustment — (1,003)
Other expense 128 65
Loss before reorganization items, net and income taxes (32,064) (463,349)
Reorganization items, net (6) (566)
Income tax expense — (115)
Net (income) loss allocated to participating restricted stockholders — —
Net loss available to common stockholders $ (32,070) $ (464,030)
Loss per share: (See Note 10)
Basic and diluted loss per share $ (0.84) $ (12.34)
Weighted average common shares outstanding:
See Accompanying Notes to Consolidated Financial Statements.
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AMPLIFY ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Year Ended
December 31,
Cash flows from operating activities: