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 2022 decreased to 31%, 3% and 3%, respectively. The decrease in production was attributable to Beta properties being shut-in due to the Incident and natural decline. We had a 21% increase in oil and natural gas sales which was from higher realized commodity prices offset by lower production changes.
Our total estimated proved reserves increased to 124.0 MMBoe in 2022 compared to 121.2 MMBoe in 2021.
As of December 31, 2022, we are the operator of record for properties containing 92% of our total estimated proved reserves.
Industry Trends
For a discussion of how industry trends have 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
Pipeline Incident Settlement
On March 1, 2023, the Company announced that the vessels that struck and damaged the Pipeline and their respective owners and operators have agreed to pay the Company $96.5 million in a settlement. The Marine Exchange has agreed to non-monetary terms as well. The overall resolution includes subrogation claims by Amplify’s property damage and loss of production insurers, with Amplify ultimately receiving a net payment of approximately $85 million. The parties are working to finalize the settlement agreement documentation. The settlement resolves Amplify’s affirmative claims related to the Incident. As part of the settlement, after payment is made, Amplify will dismiss all of its legal claims against those parties. For a discussion regarding the Incident, see Note 15 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.
Borrowing Base Redetermination Agreement and Seventh Amendment
On December 9, 2022, OLLC, entered into the Seventh Amendment. The Seventh Amendment amends the parties’ Credit Agreement, to, among other things:
● extend the maturity date from November 2, 2023 to May 31, 2024;
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● adjust the minimum hedging requirements;
● remove the Borrower’s ability to pay dividends through the maturity date.
Director and Certain Officer Departures and Appointments
On February 27, 2023, Jason McGlynn notified the Company of his decision to resign. Mr. McGlynn will cease to serve as Chief Financial Officer of the Company effective March 17, 2023 (the “Separation Date”). Mr. McGlynn’s decision to resign stems solely from personal reasons and did not result from any disagreement with the Company or the board of directors.
Subject to Mr. McGlynn’s execution and non-revocation of a general release of claims and continued employment by the Company until the Separation Date, Mr. McGlynn’s 8,334 unvested time-based restricted stock units scheduled to vest on April 1, 2023 pursuant to the applicable award agreement will vest in full on the Separation Date.
On November 29, 2022, Richard P. Smiley notified the Company of his intent to retire and resign from his current position as Senior Vice President, Operations, which decision stemmed solely from personal reasons and did not result from any disagreement with the Company or any matter relating to the Company’s operations, policies or practices. Mr. Smiley intends to remain in his role at the Company to assist with an orderly transition of his responsibilities, and to continue to provide essential transition services to the Company following his retirement.
Effective December 31, 2022, Eric T. Greager resigned from the Company’s board of directors to pursue another career opportunity. Mr. Greager’s decision to leave the Company for another career opportunity was not a result of any disagreement with the Company or its board of directors or any matter relating to the Company’s financials, operations, policies or practices.
On February 9, 2023, the Company’s board of directors appointed James E. Craddock to the board of directors. Mr. Craddock has also been appointed to the nominating and governance committee of the board of directors.
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.
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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).
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, 2022:
NYMEX-WTI oil future price range per Bbl $ 122.11 $ 71.02
NYMEX-Henry Hub natural gas future price range per MMBtu $ 9.68 $ 3.72
ICE Brent oil future price range per Bbl $ 123.58 $ 76.10
For the Five Years Ended December 31, 2022:
NYMEX-WTI oil future price range per Bbl $ 122.11 $ (37.63)
NYMEX-Henry Hub natural gas future price range per MMBtu $ 9.68 $ 1.48
ICE Brent oil future price range per Bbl $ 123.58 $ 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% -75% 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.
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Principal Components of Cost Structure
Outlook
Based on our current plans, our capital expenditure program for the full year 2023 is expected to be approximately $30.0 million to $40.0 million. The charts below detail the allocation of capital across our asset base and by investment type based on the midpoint of our 2023 capital expenditure range.
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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 2023 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.
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.
We review the carrying value of our oil and natural gas properties for impairments annually or when events and circumstances indicate the carrying value of our properties may not be recoverable. Such indications could be the result of downward revisions 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.
We believe accounting for oil and natural gas properties is a critical accounting estimate because the policies discussed above the impact the carrying value of our properties involve significant judgments about the impact of future events on our estimated cash flows. Future events and circumstances currently unknown to us could require future impairments to our properties and materially change the carrying value of our properties.
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.
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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, 2022 and 2021.
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.
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.
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.
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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.
Income Tax. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards.
In assessing the carrying value of our net deferred tax assets, we consider the realizability of our deferred tax assets each reporting period. The realization of any deferred tax asset is dependent upon the generation of future taxable income sufficient to demonstrate our ability to utilize the deferred tax asset in the period in which the temporary differences become deductible or in a future period prior to expiration. We considered all available evidence, including cumulative historical losses (defined as pre-tax earnings as adjusted for permanent tax adjustment), scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. Based on all positive and negative evidence, we concluded that it was more likely than not that all of our net deferred tax assets would not be fully realized and maintained a full valuation allowance of $284.9 million at December 31, 2022.
We believe accounting for income taxes is a critical accounting estimate because the policies discussed above in assessing the carrying value of our net deferred tax assets require estimates and judgements about the impact of future events on our projected taxable income. For example, our cumulative historical losses for the three fiscal years end December 31, 2022, 2021 and 2020 are $434.1 million, which is primarily attributable to impairment expenses of $476.9 million that were incurred during the fiscal year ended December 31, 2020. In future periods, we may demonstrate cumulative historical earnings for the previous three fiscal years, which could significantly impact our valuation allowance of $284.9 million as of December 31, 2022. Any reduction in the valuation allowance would increase our income tax benefit in the Consolidated Statements of Operations.
Results of Operations
The results of operations for the years ended December 31, 2022 and 2021, have been derived from our Consolidated Financial Statements. The comparability of the results of operations among the periods presented below is impacted by the Incident and suspension of operations at our Beta properties.
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The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.
For the Year Ended
December 31,
($ In thousands)
Gathering, processing and transportation 29,110 20,807
Depreciation, depletion and amortization 23,950 28,068
General and administrative expense 30,164 25,285
Loss (gain) on commodity derivative instruments 106,937 142,439
Pipeline incident settlement 12,000 —
Gain on extinguishment of debt — 5,516
Oil and natural gas revenues:
Production volumes:
Average net production (MBoe/d) 20.7 24.0
Average realized sales price (excluding commodity derivatives):
Natural gas (per Mcf) 6.43 3.46
Average unit costs per Boe:
Lease operating expense $ 17.45 $ 13.88
Gathering, processing and transportation 3.86 2.38
Taxes other than income 4.41 2.54
General and administrative expense 4.00 2.89
Depletion, depreciation and amortization 3.17 3.21
For the year ended December 31, 2022 compared to the year ended December 31, 2021
Net income of $57.9 million and net loss of $32.1 million was recorded for the year ended December 31, 2022 and 2021, respectively.
Oil, natural gas and NGL revenues were $407.8 million and $335.8 million for the year ended December 31, 2022 and 2021, respectively. Average net production volumes were approximately 20.7 MBoe/d and 24.0 MBoe/d for the year ended December 31, 2022 and 2021, respectively. The change in production volumes was primarily due to the suspension of operations at our Beta properties and natural declines. For the year ended December 31, 2021, production from our Beta properties was 2.73 MBoe/d. The average realized sales price was $54.02 per Boe and $38.39 per Boe for the year ended December 31, 2022 and 2021, respectively. The increase in average realized sales price was primarily due to the increase in commodity prices.
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Other revenues were $50.7 million and $7.1 million for the year ended December 31, 2022 and 2021, respectively. The change in other revenues was primarily related the recognition of loss of production income insurance proceeds of $50.2 million for the year ended December 31, 2022 compared to $6.7 million for the year ended December 31, 2021.
Lease operating expense was $131.7 million and $121.4 million for the year ended December 31, 2022 and 2021, respectively. The change in lease operating expense was primarily related to a $11.6 million increase in base lease operating expense due to higher aggregate costs and a $8.4 million increase in our workover expenses primarily in Wyoming and Oklahoma. The increase was offset by a decrease of $9.6 million in lease operating expense at our Beta properties, mainly due to the suspension of operations. On a per Boe basis, lease operating expense was $17.45 and $13.88 for the year ended December 31, 2022 and 2021, respectively. The change in lease operating expense on a per Boe basis was mainly due to higher aggregate costs noted above and lower production.
Gathering, processing and transportation expenses were $29.1 million and $20.8 million for the year ended December 31, 2022 and 2021, respectively. The increase in gathering, processing and transportation expenses was primarily attributable to a change in the marketing of our natural gas in Oklahoma in October 2021. At that time, we began marketing our own natural gas in Oklahoma and that has greatly improved our natural gas differentials, but we must now recognize certain revenue deductions as gathering, processing and transportation expense on a go-forward basis. On a per Boe basis, gathering, processing and transportation expenses were $3.86 and $2.38 for the year ended December 31, 2022 and 2021, respectively. The change on a per BOE basis is primarily related to the marketing changes discussed above.
Taxes other than income was $33.3 million and $22.3 million for the year ended December 31, 2022 and 2021, respectively. The change in taxes other than income is due to an increase of $10.0 million in production taxes as a result of the increase in commodity prices and an increase of $1.0 million for ad valorem tax. On a per Boe basis, taxes other than income were $4.41 and $2.54 for the year ended December 31, 2022 and 2021, 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 $24.0 million and $28.1 million for the year ended December 31, 2022 and 2021, respectively. The change in DD&A expense was primarily due to a 14% decrease in production due to the suspension of operations at our Beta properties and natural decline.
General and administrative expense was $30.2 million and $25.3 million for the year ended December 31, 2022 and 2021, respectively. The change in general and administrative expense is primarily related to (i) an increase of $1.9 million in salaries and other payroll benefits; (ii) an increase of $1.5 million in stock compensation expense; (iii) an increase in professional services of $0.6 million; and an increase in legal services of $0.5 million.
Net losses on commodity derivative instruments of $106.9 million were recognized for the year ended December 31, 2022, consisting of a $41.3 million increase in the fair value of open positions and a decrease of $148.2 million in cash settlements paid on expired positions. Net losses 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.
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.
Pipeline incident loss was $11.3 million and $1.6 million for the year ended December 31, 2022 and 2021. The $11.3 million reflects certain legal defense costs associated with the Incident that are not expected to be recovered under an insurance policy. See Note 15 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
Pipeline incident settlement was $12.0 million for the year ended December 31, 2022, related to the resolution of the federal and state matters associated with the Incident discussed in Note 15 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report. No expense was recorded for the year ended December 31, 2021.
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Interest expense, net was $14.1 million and $12.1 million for the year ended December 31, 2022 and 2021, respectively. The change in interest expense was from a $2.8 million increase in interest expense due to higher interest rates on our Revolving Credit Facility, offset by a decrease of $0.7 million on our interest rate swaps.
Average outstanding borrowings under our Revolving Credit Facility were $215.1 million and $240.2 million for the year ended December 31, 2022 and 2021, 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 $5.5 million loan that the Company received on April 24, 2020 under the Paycheck Protection Program (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.
For the year ended December 31, 2021 compared to the year ended December 31, 2020
Information related to the comparison of our discussion of the results of operations for the year ended December 31, 2021, compared to the year ended December 31, 2020, is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2021 Form 10-K filed with the SEC and is incorporated by reference into this Annual Report.
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;
● Restructuring related costs;
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● 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)
Losses (gains) on commodity derivative instruments 106,937 142,439
Pipeline incident settlement 12,000 —
Share-based compensation expense 3,086 1,612
Gain on extinguishment of debt — (5,516)
Loss on settlement of AROs 908 11
Income tax expense 111 —
Exploration costs 57 57
Acquisition and divestiture related expenses 41 19
Bad debt expense 1 95
Reorganization items, net — 6
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
For the Year Ended
December 31,
(In thousands)
Net cash provided by operating activities $ 64,485 $ 62,969
Gain (loss) on interest rate swaps 935 217
Cash settlements paid (received) on interest rate swaps (311) 1,912
Pipeline incident settlement 12,000 —
Plugging and abandonment cost 1,829 307
Amortization and write-off of deferred financing fees (649) (626)
Acquisition and divestiture related expenses 41 19
Exploration costs 57 57
Reorganization items, net — 6
Income tax expense - current portion 111 —
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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 2023 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 2023 capital program from internally generated cash flow, borrowings under our Revolving Credit Facility and/or debt or equity financings may provide incremental financial flexibility. We believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our Revolving Credit Facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter.
Impact of the Southern California Pipeline Incident. There is certain 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 certain costs as a result of the Incident, and the continued suspension of production from Beta may lead to a material reduction in revenue from these assets. However, in addition to the settlement amount disclosed elsewhere in this Annual Report that we will receive from the vessels that struck and damaged the Pipeline and their respective owners and operators, we carry customary insurance policies, which have covered a material portion of aggregate costs, including loss of production income insurance to offset loss of revenue resulting from suspended operations. The loss of production income insurance related to the Incident will expire on March 31, 2023. 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% - 75% 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 $35.8 million for the year ended December 31, 2022, which were primarily related to capital workovers and capital facilities expenditures located in the Rockies, Oklahoma and East Texas 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
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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.
As of December 31, 2022, we had a working capital deficit of $40.6 million primarily as the result of (i) a short-term derivative liability balance of $20.9 million (ii) an accrued liabilities balance of $58.4 million (iii) an accounts payable balance of $38.4 million, and (iv) a revenue payable balance of $22.1 million, less (i) an accounts receivable balance of $80.5 million and (ii) prepaid expenses and other current assets 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, 2022, 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, 2022, was $210.0 million.
On December 9, 2022, OLLC entered into the Seventh Amendment. The Seventh Amendment amends the Credit Agreement, to, among other things:
● extend the maturity date from November 2, 2023 to May 31, 2024;
● adjust the minimum hedging requirements;
● remove the Borrower’s ability to pay dividends through the maturity date.
On June 20, 2022, OLLC entered into the Borrowing Base Redetermination and Sixth Amendment to Credit Agreement, by and among OLLC, Acquisitionco, each of the guarantors party thereto, each of the lenders party thereto and KeyBank National Association, as administrative agent for the lenders (the “Sixth Amendment”). The Sixth Amendment amends the Revolving Credit Facility to, among other things:
● terminate the automatic monthly reductions of the borrowing base;
● modify the affirmative hedging covenant.
As of December 31, 2022, 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, 2022, we had approximately $20.0 million of available borrowings under our Revolving Credit Facility.
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.
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.
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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, 2022, our future commitments under these contracts were $6.1 million in 2023, $1.6 million in 2024, $1.6 million in 2025, $1.6 million in 2026, $1.1 million in 2027 and $2.9 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.
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, 2022, our future commitments under this agreement were $8.0 million in 2023, and $15.8 million a year for years 2024 through 2033. 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.
Fines. We have a payment plan to pay our federal fines over a period of three years. We are scheduled to pay $2.0 million in each of 2023 and 2024 and $1.1 million in 2025. For the fines related to the state of California, we are scheduled to pay $2.9 million in 2023.
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, 2022 and 2021, 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 $ 64,485 $ 62,969
Net cash used in investing activities (41,525) (29,428)
Net cash used in financing activities (41,759) (25,106)
For the year ended December 31, 2022 compared to the year ended December 31, 2021
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $64.5 million and $63.0 million for the year ended December 31, 2022 and 2021, respectively. Production volumes decreased to 20.7 MBoe/d in 2022 from 24.0 MBoe/d in 2021 and the average realized sales price increased to $54.02 per Boe in 2022 from $38.39 per Boe in 2021. The changes in production and average realized sales price were primarily related to the suspension of operations at Beta and increased realized commodity prices.
Net cash provided by operating activities for the year ended December 31, 2022 included $147.9 million of cash paid on expired derivative instruments compared to $90.2 million of cash paid on expired derivative instruments for the year ended December 31, 2021. For the year ended December 31, 2022, we had net losses on commodity derivative instruments of $106.9 million compared to net losses of $142.4 million for the year ended December 31, 2021.
During 2021, 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, 2022, was $41.5 million, of which $34.8 million was used for additions to oil and natural gas properties. 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 natural gas properties.
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California properties. Additions to restricted investments were $6.7 million for the year ended December 31, 2022.
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Financing Activities. We had net repayments of $40.0 million and $25.0 million under our Revolving Credit Facility for the year ended December 31, 2022 and 2021, respectively.
For the year ended December 31, 2021 compared to the year ended December 31, 2020
Information related to the comparison of our discussion of the cash flows for the year ended December 31, 2021 compared to the year ended December 31, 2020, is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” of our 2021 Form 10-K filed with the SEC and is incorporated by reference into this Annual Report.
Capital Requirements
See “— Outlook” for additional information regarding our capital spending program for 2023.
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) of 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, 2022.
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, 2022, 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, 2022. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2022, 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, 2022, 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
To the shareholders and Board of Directors of 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, 2022, 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, 2022, 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, 2022, of the Company and our report dated March 9, 2023, 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, 2023
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ITEM 9B.OTHER INFORMATION
None.
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 2023 Annual Meeting of Stockholders of Amplify Energy Corp. (the “Proxy Statement”) that is expected to be held in May 2023.
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
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ExhibitNumber Description
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
* 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, 2023 By: /s/ Jason McGlynn
Name: Jason McGlynn
Title: Senior Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, 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, 2023
Martyn Willsher (Principal Executive Officer)
Jason McGlynn (Principal Financial Officer)
/s/ Eric Dulany Vice President and Chief Accounting Officer March 9, 2023
Eric Dulany (Principal Accounting Officer)
/s/ Christopher W. Hamm Chairman and Director March 9, 2023
Christopher W. Hamm
/s/ Deborah Adams Director March 9, 2023
Deborah Adams
/s/ James E. Craddock Director March 9, 2023
James E. Craddock
/s/ Patrice Douglas Director March 9, 2023
Patrice Douglas
/s/ Randal T. Klein Director March 9, 2023
Randal T. Klein
/s/ Todd R. Snyder Director March 9, 2023
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, 2022 and December 31, 2021 F-4
Notes to Consolidated Financial Statements F-8
Note 1 – Organization and Basis of Presentation F-8
Note 2 – Summary of Significant Accounting Policies F-8
Note 3 – Revenues F-13
Note 4 – Fair Value Measurements of Financial Instruments F-14
Note 5 – Risk Management and Derivative Instruments F-16
Note 6 – Asset Retirement Obligations F-18
Note 7 – Restricted Investments F-18
Note 8 – Debt F-19
Note 9 – Equity (Deficit) F-21
Note 10 – Earnings per Share F-22
Note 11 – Equity-based Awards F-22
Note 12 – Leases F-26
Note 14 – Related Party Transactions F-29
Note 15 – Southern California Pipeline Incident F-29
Note 16 – Commitments and Contingencies F-32
Note 17 – Income Tax F-34
Note 18 – Supplemental Oil and Gas Information (Unaudited) F-37
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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, 2022 and 2021, the related consolidated statements of operations, stockholders’ equity, and cash flows, for each of the two years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2022, 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, 2022, 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, 2023, 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 matter communicated below is a matter arising from the current‐period audit of the financial statements that was 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Oil and Natural Gas Properties and Depletion – Oil and Natural Gas Reserve Quantities — Refer to Notes 2 and 18 to the financial statements
Critical Audit Matter Description
The Company’s proved oil and natural gas properties are depleted 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, net of accumulated depreciation were $315.7 million as of December 31, 2022, and depletion expense was $21.8 million 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
We evaluated the Company’s estimates around production volumes by evaluating the wells’ past production performance to confirm it was appropriately reflected in production forecasts used in generating proved reserves.
We evaluated the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm, including the methodologies and calculation procedures used to estimate oil and natural gas reserves and performed analytical procedures on the reserve quantities.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 9, 2023
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:
Cash and cash equivalents $ — $ 18,799
Prepaid expenses and other current assets 18,789 15,018
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method 840,310 799,532
Accumulated depreciation, depletion and amortization (658,162) (634,212)
Operating lease - long term right-of-use asset 7,376 2,716
LIABILITIES AND EQUITY
Current liabilities:
Short-term derivative instruments 20,884 53,144
Long-term derivative instruments — 9,664
Operating lease liability 6,567 2,017
Commitments and contingencies (see Note 16)
Stockholders' equity (deficit):
Total stockholders' deficit (4,565) (64,841)
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 29,110 20,807
Depreciation, depletion and amortization 23,950 28,068
General and administrative expense 30,164 25,285
Accretion of asset retirement obligations 7,081 6,611
Loss (gain) on commodity derivative instruments 106,937 142,439
Pipeline incident settlement 12,000 —
Other income (expense):
Gain on extinguishment of debt — 5,516
Other income (expense) 98 128
Total other income (expense) (14,003) (6,455)
Reorganization items, net — (6)
Income tax expense (111) —
Allocation of net income (loss) to:
Net income (loss) available to common stockholders 55,147 (32,070)
Net income (loss) allocated to participating securities 2,728 —
Net income (loss) available to Amplify Energy Corp. $ 57,875 $ (32,070)
Earnings (loss) per share: (See Note 10)
Basic and diluted earnings (loss) per share $ 1.44 $ (0.84)
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:
Depreciation, depletion and amortization 23,950 28,068
Gain on extinguishment of debt — (5,516)
Accretion of asset retirement obligations 7,081 6,611