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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2020

 

OR

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                      to                     .

 

Commission File Number: 001-35512

 

AMPLIFY ENERGY CORP.

(Exact name of registrant as specified in its charter)

 

Delaware

 

82-1326219

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

500 Dallas Street, Suite 1700, Houston, TX

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (713) 490-8900

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock

AMPY

NYSE

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes      No      

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes      No  

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes      No  

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b–2 of the Exchange Act.

 Large accelerated filer

 

  

Accelerated filer

 

Non-accelerated filer

 

  

Smaller reporting company

 

Emerging growth company

 

 

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)  Yes      No  

The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $33.2 million on June 30, 2020, based on $1.23 per share, the last reported sales price of the shares on the New York Stock Exchange on such date.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes     No  

As of February 26, 2021, the registrant had 37,943,167 outstanding shares of Common Stock, $0.01 par value per share.

Documents Incorporated By Reference: Portions of the registrant’s definitive proxy statement relating to its 2021 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2020, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Form 10-K.

 

 


 

AMPLIFY ENERGY CORP.

TABLE OF CONTENTS

 

 

 

 

  

Page

 

 

 

PART I

  

 

Item 1.

 

Business

  

10

Item 1A.

 

Risk Factors

  

32

Item 1B.

 

Unresolved Staff Comments

  

46

Item 2.

 

Properties

  

46

Item 3.

 

Legal Proceedings

  

47

Item 4.

 

Mine Safety Disclosures

  

47

 

 

 

PART II

  

 

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  

48

Item 6.

 

Selected Financial Data

  

48

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

49

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  

62

Item 8.

 

Financial Statements and Supplementary Data

  

62

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  

62

Item 9A.

 

Controls and Procedures

  

63

Item 9B.

 

Other Information

  

63

 

 

 

PART III

  

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  

64

Item 11.

 

Executive Compensation

  

64

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  

64

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  

64

Item 14.

 

Principal Accountant Fees and Services

  

64

 

 

 

PART IV

  

 

Item 15.

 

Exhibits, Financial Statement Schedules

  

65

Item 16.

 

Form 10-K Summary

 

68

 

Signatures

  

69

 

 

 

 


 

GLOSSARY OF OIL AND NATURAL GAS TERMS

3-D seismic: Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

API Gravity: A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

Basin: A large depression on the earth’s surface in which sediments accumulate.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d: One Bbl per day.

Bcfe: One billion cubic feet of natural gas equivalent.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Boe/d: One Boe per day.

BOEM: Bureau of Ocean Energy Management.

BSEE: Bureau of Safety and Environmental Enforcement.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one-degree Fahrenheit.

Deterministic Estimate: The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

ICE: Inter-Continental Exchange.

1


MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand barrels of oil equivalent.

MBoe/d: One thousand barrels of oil equivalent per day.

MMBoe: One million barrels of oil equivalent.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

MMcfe/d: One MMcfe per day.

Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Plugging and abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues or PV-9: The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 9% in accordance with the guidelines of the U.S. Securities Exchange Commission (the “SEC”).

Present value of future net revenues or PV-10: The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

2


Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

3


Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses and discounted at 10% per annum to reflect the timing of future net revenue. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in our oil and natural gas properties. Standardized measure does not give effect to derivative transactions.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and generally requires the owner to pay a share of the costs of drilling and production operations.

Workover: Operations on a producing well to restore or increase production.

WTI: West Texas Intermediate.

4


NAMES OF ENTITIES

As used in this Form 10-K, unless we indicate otherwise:

 

“Amplify Energy” “Company,” “we,” “our,” “us,” or like terms refers to Amplify Energy Corp. (f/k/a Midstates Petroleum Company, Inc.) individually and collectively with its subsidiaries, as the context requires;

 

“Company,” “we,” “our,” “us” or like terms refers to Amplify Energy Corp. for periods presented after the effective date of the Merger (as defined below) and to Legacy Amplify for periods presented prior to effective date of the Merger;

 

“Legacy Amplify” refers to Amplify Energy Holding LLC (f/k/a Amplify Energy Corp.), the successor reporting Company of Memorial Production Partners LP, which is now a wholly owned subsidiary of Amplify Energy Corp.;

 

“Midstates” refers to Midstates Petroleum Company, Inc., which on the effective date of the Merger (as defined below) changed its name to “Amplify Energy Corp.”; and

 

“OLLC” refers to Amplify Energy Operating LLC, our wholly owned subsidiary through which we operate our properties.

5


 

FORWARD–LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

business strategies;

 

acquisition and disposition strategy;

 

cash flows and liquidity;

 

financial strategy;

 

ability to replace the reserves we produce through drilling;

 

drilling locations;

 

oil and natural gas reserves;

 

technology;

 

realized oil, natural gas and NGL prices;

 

production volumes;

 

lease operating expense;

 

gathering, processing and transportation;

 

general and administrative expense;

 

future operating results;

 

ability to procure drilling and production equipment;

 

ability to procure oil field labor;

 

planned capital expenditures and the availability of capital resources to fund capital expenditures;

 

ability to access capital markets;

 

marketing of oil, natural gas and NGLs;

 

acts of God, fires, earthquakes, storms, floods, other adverse weather conditions, war, acts of terrorism, military operations or national emergency;

 

the occurrence or threat of epidemic or pandemic diseases, such as the ongoing novel coronavirus (“COVID-19”) pandemic, or any government response to such occurrence or threat;

 

expectations regarding general economic conditions;

 

competition in the oil and natural gas industry;

 

effectiveness of risk management activities;

 

environmental liabilities;

 

counterparty credit risk;

 

expectations regarding governmental regulation and taxation;

 

expectations regarding developments in oil-producing and natural-gas producing countries; and

 

plans, objectives, expectations and intentions.

6


 

All statements, other than statements of historical fact, included in this report are forward-looking statements. These forward-looking statements may be found in “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following risks and uncertainties:

 

our results of evaluation and implementation of strategic alternatives;

 

risks related to a redetermination of the borrowing base under our senior secured reserve-based revolving credit facility;

 

our ability to access funds on acceptable terms, if at all, because of the terms and conditions governing our indebtedness, including financial covenants;

 

our ability to satisfy our debt obligations;

 

volatility in the prices for oil, natural gas and NGLs, including further or sustained declines in commodity prices;

 

the potential for additional impairments due to continuing or future declines in oil, natural gas and NGL prices;

 

the uncertainty inherent in estimating quantities of oil, natural gas and NGL reserves;

 

our substantial future capital requirements, which may be subject to limited availability of financing;

 

the uncertainty inherent in the development and production of oil and natural gas;

 

our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;

 

the existence of unanticipated liabilities or problems relating to acquired or divested businesses or properties;

 

potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties;

 

the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;

 

potential shortages of, or increased costs for, drilling and production equipment and supply materials for production, such as CO2;

 

potential difficulties in the marketing of oil and natural gas;

 

changes to the financial condition of counterparties;

 

uncertainties surrounding the success of our secondary and tertiary recovery efforts;

 

competition in the oil and natural gas industry;

 

general political and economic conditions, globally and in the jurisdictions in which we operate;

 

the impact of climate change and natural disasters, such as earthquakes, tidal waves, mudslides, fire and floods;

 

the impact of legislation and governmental regulations, including those related to climate change and hydraulic fracturing;

 

the risk that our hedging strategy may be ineffective or may reduce our income;

 

the cost and availability of insurance as well as operating risks that may not be covered by an effective indemnity or insurance;

 

actions of third-party co-owners of interest in properties in which we also own an interest; and

 

other risks and uncertainties described in “Item 1A. Risk Factors.”

7


 

The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Item 1A. Risk Factors” and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

8


RISK FACTOR SUMMARY

Our business is subject to numerous risks and uncertainties, including those highlighted in this section titled “Risk Factors” and summarized below. We have various categories of risks, including risks related to our business and industry, risks related to information technology, data security and privacy, risks related to legal, regulatory, accounting, and tax matters, risks related to our Common Stock, and risks related to our Revolving Credit Facility, which are discussed more fully below. As a result, this risk factor summary does not contain all of the information that may be important to you, and you should read this risk factor summary together with the more detailed discussion of risks and uncertainties set forth following this section under the heading “Risk Factors,” as well as elsewhere in this Annual Report. These risks include, but are not limited to, the following:

 

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

 

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

 

The oversupply of oil and natural gas and lower demand caused by COVID-19 pandemic, the failure of oil producing countries to sufficiently curtail production and general global economic instability may result in transportation and storage constraints, reduced production or the shut-in of our producing wells, any of which would adversely affect our business, financial condition and results of operations.

 

Our business operations, financial position, results of operations, and cash flows have been and may be adversely affected by the COVID-19 pandemic.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We are currently out of compliance with the NYSE minimum market capitalization requirement and are at risk of the NYSE delisting our Common Stock, which would have an adverse impact on the trading volume, liquidity and market price of our Common Stock.

 

 

 

9


PART I

ITEM 1.

BUSINESS

References

On August 6, 2019, Midstates Petroleum Company, Inc., a Delaware corporation (“Midstates”), completed its business combination (the “Merger”) with Amplify Energy Corp., a Delaware corporation (“Legacy Amplify”), in accordance with the terms of that certain Agreement and Plan of Merger, dated May 5, 2019 (the “Merger Agreement”), by and among Midstates, Legacy Amplify and Midstates Holdings, Inc., a Delaware corporation and direct, wholly owned subsidiary of Midstates (“Merger Sub”). Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates, and immediately following the Merger, Legacy Amplify merged with and into Alpha Mike Holdings LLC, a Delaware limited liability company and wholly owned subsidiary of Midstates (“LLC Sub”), with LLC Sub surviving as a wholly owned subsidiary of Midstates. On the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.” (the “Company”) and LLC Sub changed its name to “Amplify Energy Holdings LLC.”

For financial reporting purposes, the Merger represented a “reverse merger” and Legacy Amplify was deemed to be the accounting acquirer in the transaction. Legacy Amplify’s historical results of operations replaced Midstates’ historical results of operations for all periods prior to the Merger and, for all periods following the Merger, the Company’s financial statements reflect the results of operations of the combined company. Accordingly, the financial statements for the Company included in this Annual Report for periods prior to the Merger are not the same as Midstates prior reported filings with the SEC, which were derived from the operations of Midstates. The results of any one quarter should not be relied upon as an indication of future performance.

When referring to Legacy Amplify, the intent is to refer to Amplify Energy Corp. prior to the Merger, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Legacy Amplify is the successor reporting company of Memorial Production Partners LP pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Overview

Amplify Energy is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on one 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, federal waters offshore Southern California, East Texas/North Louisiana, and Eagle Ford. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs.

The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. As of December 31, 2020:

 

Our total estimated proved reserves were approximately 113.8 MMBoe, of which approximately 41% were oil and 85% were classified as proved developed reserves;

 

We produced from 2,448 gross (1,354 net) producing wells across our properties, with an average working interest of 55% and the Company is the operator of record of the properties containing 92% of our total estimated proved reserves; and

 

Our average net production for the three months ended December 31, 2020 was 26.3 MBoe/d, implying a reserve-to-production ratio of approximately 12 years.

Industry Trends

In March 2020, the World Health Organization declared a global pandemic related to the proliferation of COVID-19. The impact of COVID-19 and efforts to mitigate its spread have caused significant volatility in U.S. and international markets and a substantial reduction in global and domestic demand for oil and natural gas. Actions by governmental authorities to mitigate the spread of COVID-19, such as imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of business facilities, and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have further exacerbated the economic impact of the pandemic.

As a result of the pandemic, there has also been a sharp reduction in the demand for oil and natural gas and a precipitous decline in commodity prices, which were further impacted by disputes over production levels among oil-producing countries, the significant increase in production levels by such countries and limited storage capacity for natural gas, oil and refined products.

10


In response to the unprecedented and extremely low commodity prices, the Company executed several liquidity enhancement initiatives to better position the Company through the downturn, including significant decreases to operating and G&A expenses, substantial reductions to capital programs, the monetization of a portion of the Company’s 2021 in-the-money crude oil hedges, the receipt of loan proceeds from the federal government’s Paycheck Protection Program, royalty relief at the Company’s Beta Properties (defined below) and the suspension of the quarterly dividend, among other things. The successful realization and execution of our liquidity enhancing initiatives, coupled with a disciplined commodity hedging program, have substantially mitigated the impact of the pandemic on the Company’s operational and financial results and demonstrated the sustainable value of our long-lived, low-decline assets.

Despite the gradual recovery in commodity prices in the second half of 2020 and the expectation of a successful phased rollout of a vaccine in 2021, we have continued our commitment to operating in a disciplined, capital efficient manner, and we remain committed to the responsible stewardship of our assets and to continue focusing on maximizing cash flows, further reducing debt, delivering low-cost capital efficient operations, and generating shareholder value. We will continue to monitor developments regarding the pandemic, the distribution of the vaccination and changes in market conditions as we pursue our business and strategic objectives.

Recent Developments

Appointment of Chief Executive Officer and Director

On January 19, 2021, the Company appointed Mr. Martyn Willsher as the Company’s President and Chief Executive Officer and member of the board of directors. Mr. Willsher had served as the Company’s Interim Chief Executive Officer since April 3, 2020 and Senior Vice President and Chief Financial Officer since April 27, 2018.

Appointment of Senior Vice President and Chief Financial Officer

On January 19, 2021, the Company appointed Mr. Jason McGlynn as the Company’s Senior Vice President and Chief Financial Officer. Mr. McGlynn had served as the Company’s Vice President of Business Development since February 3, 2020.

Resignation of Chairman of the Board of Directors

On January 19, 2021, Mr. David H. Proman announced his resignation from his position as Chairman of the board of directors of the Company. Mr. Proman retained his seat as a member of the board of directors.

Appointment of Chairman of the Board of Directors

Concurrently with Mr. Proman’s resignation, the board of directors unanimously approved and appointed Mr. Christopher W. Hamm as the Company’s new Chairman of the board of directors.

Appointment of Director to the Board of Directors

On February 10, 2021, Ms. Patrice Douglas was appointed as a member of the Company’s board of directors and will also serve on the Company’s audit committee.

Secondary Public Offering of Common Stock for Selling Stockholders

On December 11, 2020, certain selling stockholders of the Company (the “Selling Stockholders”), Roth Capital Partners, LLC (the “Underwriter”) and the Company entered into an underwriting agreement, pursuant to which the Selling Stockholders agreed to sell to the Underwriter, and the Underwriter agreed to purchase from the Selling Stockholders, subject to and upon the terms and conditions set forth therein, an aggregate of 8,548,485 shares of common stock, par value $0.01 per share of the Company (“Common Stock”). The offering closed on December 15, 2020. The Company did not receive any proceeds from the sale of shares of Common Stock in the offering.

The offering was made pursuant to effective shelf registration statements (File No. 333-233677, effective October 11, 2019, and 333-215602, effective May 1, 2018) and prospectuses filed by the Company with the SEC. The offering of these securities was made only by means of a prospectus and prospectus supplement.

Borrowing Base Redetermination

On November 18, 2020, as part of the Company’s fall 2020 semiannual borrowing base redetermination, the borrowing base and lender commitments under the Company’s credit agreement among wholly owned subsidiaries of the Company, Bank of Montreal, as administrative agent, and other lenders party thereto (as amended from time to time, the “Revolving Credit Facility”) reaffirmed the borrowing base at $260.0 million, with the next such redetermination scheduled for spring 2021. The Revolving Credit Facility is a reserve-based revolving credit facility with a maturity date of November 2, 2023, and semiannual borrowing base redeterminations.

11


Notice of Non-Compliance with New York Stock Exchange (“NYSE”) Continued Listing Standards

On August 31, 2020, the Company, received written notification (the “Market Cap Notice”) from the NYSE that the Company no longer satisfied the continued listing compliance standards set forth under Section 802.01B of the NYSE Listed Company Manual (the “Manual”) because the average global market capitalization of the Company was less than $50,000,000 over a consecutive 30 trading-day period that ended on August 28, 2020 and, at the same time, the Company’s stockholders’ equity was less than $50,000,000 (the “Market Cap Deficiency”).

Under NYSE procedures, the Company had 45 days from its receipt of the Market Cap Notice to submit a plan to the NYSE demonstrating how it intends to regain compliance with the NYSE’s continued listing standards within 18 months. The Company submitted its plan to regain compliance with the listing standards within the required timeframe.

In addition, on October 13, 2020, the Company received written notification (the “Share Price Notice”) from the NYSE that the Company no longer satisfied the continued listing compliance standards set forth under Section 802.01C of the Manual because the average closing price of the Company’s Common Stock was below $1.00 over a 30 consecutive trading-day period that ended October 12, 2020 (the “Share Price Deficiency”). Under the NYSE’s rules, the Company had six months following receipt of the Share Price Notice to regain compliance with the minimum share price requirement.

The Company notified the NYSE of its intent to cure the Share Price Deficiency and return to compliance with the NYSE’s continued listing requirements. On January 4, 2021, the Company received written notification from the NYSE that the Company regained compliance with the NYSE’s continued listing standards. The Company regained compliance after its average closing price for the 30 trading-day period ended December 31, 2020 and its closing price on December 31, 2020 both exceeded $1.00 per share.

Under NYSE rules, the Common Stock will continue to be listed on the NYSE during the cure period related to the Market Cap Deficiency, subject to the Company’s compliance with other continued listing requirements. The Common Stock’s trading symbol “AMPY” was assigned a “.BC” indicator by the NYSE to signify that the Company currently is not in compliance with the NYSE’s continued listing requirements. If the Company fails to regain compliance with Sections 802.01B of the Manual during the cure period, the Common Stock will be subject to the NYSE’s suspension and delisting procedures.

Properties

We engaged Cawley, Gillespie and Associates, Inc. (“CG&A”), our independent reserve engineers, to prepare our reserves estimates for all of our proved reserves at December 31, 2020 and 2019. The following table summarizes information, based on a reserve report prepared by CG&A (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2020 and our average net production for the three months ended December 31, 2020:

 

 

Estimated Net Proved Reserves

 

 

 

 

 

 

Average Net Production

 

 

Average Reserve-to

 

 

Producing Wells

 

Region

MMBoe (1)

 

 

% Oil and

NGL

 

 

% Natural

Gas

 

 

% Proved

Developed

 

 

Standardized

Measure (2)

 

 

MBoe/d

 

 

% of

Total

 

 

Production Ratio (3)

 

 

Gross

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

 

 

 

(Years)

 

 

 

 

 

 

 

 

 

Oklahoma

 

39.3

 

 

49%

 

 

51%

 

 

80%

 

 

$

96

 

 

 

7.5

 

 

28%

 

 

 

14.4

 

 

 

335

 

 

 

242

 

Rockies

 

21.2

 

 

100%

 

 

0%

 

 

87%

 

 

 

47

 

 

 

4.0

 

 

15%

 

 

 

14.4

 

 

 

137

 

 

 

137

 

California

 

16.7

 

 

100%

 

 

0%

 

 

66%

 

 

 

59

 

 

 

3.6

 

 

14%

 

 

 

12.7

 

 

 

53

 

 

 

53

 

East Texas/ North Louisiana

 

34.4

 

 

25%

 

 

75%

 

 

100%

 

 

 

78

 

 

 

10.4

 

 

39%

 

 

 

9.1

 

 

 

1,609

 

 

 

899

 

Eagle Ford

 

2.2

 

 

91%

 

 

9%

 

 

54%

 

 

 

18

 

 

 

0.8

 

 

3%

 

 

 

7.6

 

 

 

314

 

 

 

23

 

Total

 

113.8

 

 

60%

 

 

40%

 

 

85%

 

 

$

298

 

 

 

26.3

 

 

100%

 

 

 

11.8

 

 

 

2,448

 

 

 

1,354

 

 

(1)

Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)

Standardized measure is calculated in accordance with Accounting Standards Codification, or ASC, Topic 932, Extractive Activities—Oil and Gas, and is calculated using SEC pricing, before market differentials, of $39.57/Bbl for crude oil and NGLs and $1.99/MMBtu for natural gas.

(3)

The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2020 by the annualized average net production for the three months ended December 31, 2020.

Our Areas of Operation

Oklahoma

Approximately 34% of our estimated proved reserves as of December 31, 2020 and approximately 28% of our average daily net production for the three months ended December 31, 2020 were located in the Oklahoma region. Our Oklahoma properties include wells and properties primarily located in Alfalfa and Woods counties in Oklahoma. Those properties collectively contained 39.3 MMBbls of estimated net proved reserves as of December 31, 2020 based on our reserve report and generated average net production of 7.5 MBoe/d for the three months ended December 31, 2020.

12


Rockies

Approximately 19% of our estimated proved reserves as of December 31, 2020 and approximately 15% of our average daily net production for the three months ended December 31, 2020 were located in the Rockies region. Our Rockies properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Rockies properties contained 21.2 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2020 based on our reserve report and generated average net production of 4.0 MBoe/d for the three months ended December 31, 2020.

California

Approximately 15% of our estimated proved reserves as of December 31, 2020 and approximately 14% of our average daily net production for the three months ended December 31, 2020 were located in federal waters offshore Southern California. These properties (the “Beta Properties”) consist of: 100% of the working interests and currently 87.6% average net revenue interest in three Pacific Outer Continental Shelf lease blocks (P-0300, P-0301 and P-0306) (referred to as the “Beta Unit”), in the Beta field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. Our Beta Properties contained 16.7 MMBbls of estimated net proved oil reserves as of December 31, 2020 based on our reserve report and generated average net production of 3.6 MBoe/d for the three months ended December 31, 2020. Oil and gas are produced from the Beta Unit via two production platforms, referred to as the Ellen and Eureka platforms, equipped with permanent drilling rigs and associated equipment. On a third platform, Elly, the oil, water and gas are separated, and the oil is prepared for sale, while the gas is burned as fuel for power and the water is recycled back into the reservoir for pressure maintenance. Sales quality oil is then pumped from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California via a 16-inch diameter oil pipeline, which extends approximately 17.5 miles. Amplify Energy’s wholly owned subsidiary, San Pedro Bay Pipeline Company, owns and operates the pipeline system.

On, June 24, 2020, the Bureau of Safety and Environmental Enforcement (“BSEE”) informed the Company that it had been approved for the Special Case Royalty Relief for the Company’s interests in the Beta Unit, effective beginning July 1, 2020. The royalty rates were reduced from 25% to 12.5% for two of the Company’s leases and from 16.67% to 8.33% for the remaining third lease. This resulted in the Company’s average net revenue interest increasing from 75.2% to 87.6%.

The Special Case Royalty Relief is subject to two key provisions related to commodity prices and capital investment. Special Case Royalty Relief will be suspended in months in which the weighted twelve-month average NYMEX oil and Henry Hub gas price exceeds $66.19 per BOE, which represents a 25% premium to the average realized price recognized by the Company during the qualification period of April 2019 to March 2020. The Special Case Royalty Relief would terminate in the event that the Company generates no benefit from the reduced rates due to the higher realized pricing for 12 consecutive months. In addition, Special Case Royalty Relief requires that during the two-year period ending June 30, 2022 (and annually thereafter), the cumulative amount of a) development costs and b) incremental royalties must exceed the value of the royalty relief benefits received by the Company for production volumes at or below the calculated production volume during the qualification period. Should this condition not be met, Special Case Royalty Relief will be terminated.

East Texas / North Louisiana

Approximately 30% of our estimated proved reserves as of December 31, 2020 and approximately 39% of our average daily net production for the three months ended December 31, 2020 were located in the East Texas/ North Louisiana region. Our East Texas/ North Louisiana properties include wells and properties primarily located in the Joaquin, Carthage, Willow Springs and East Henderson fields in East Texas. Those properties collectively contained 34.4 MMBoe of estimated net proved reserves as of December 31, 2020 based on our reserve report and generated average net production of 10.4 MBoe/d for the three months ended December 31, 2020.

Eagle Ford

Approximately 2% of our estimated proved reserves as of December 31, 2020 and approximately 3% of our average daily net production for the three months ended December 31, 2020 were located in the Eagle Ford region. Our Eagle Ford properties include wells and properties in fields located primarily in the Eagleville fields. Our Eagle Ford properties contained 2.2 MMBoe of estimated net proved reserves as of December 31, 2020 based on our reserve report. Those properties collectively generated average net production of 0.8 MBoe/d for the three months ended December 31, 2020.

Our Oil and Natural Gas Data

Our Reserves

Internal Controls. Our proved reserves were estimated at the well or unit level for reporting purposes by CG&A, our independent reserve engineers. The Company maintains internal evaluations of our reserves in a secure reserve engineering database. CG&A interacts with the Company’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting, and marketing employees to obtain the necessary data to prepare the Company’s proved reserves report. Reserves are reviewed and approved internally by our senior management on an annual basis and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our Revolving Credit Facility. Our reserve estimates are prepared by CG&A at least annually.

13


Our internal professional staff works closely with CG&A to ensure the integrity, accuracy and timeliness of data that is furnished to them in order to prepare the reserves report. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide CG&A other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their preparation of our reserves.

Qualifications of Responsible Technical Persons

Internal Engineers. Tony Lopez is the technical person at the Company primarily responsible for overseeing and providing oversight of the preparation of the reserves estimates with our third-party reserve engineers.

Mr. Lopez has over 15 years of corporate reserve reporting experience. Mr. Lopez joined the Company as Vice President of Corporate Reserves in June 2018 and currently serves as the Company’s Senior Vice President of Engineering, Exploitation and Information Technology. Prior to that Mr. Lopez was Vice President of Acquisitions and Engineering for EnerVest, Ltd., where he managed the corporate reserve reporting process and the financial planning & analysis department. Mr. Lopez is a graduate of West Virginia University and holds a B.S. in Petroleum and Natural Gas Engineering. Mr. Lopez is an active member of the Society of Petroleum Engineers.

Cawley, Gillespie and Associates, Inc. CG&A is an independent oil and natural gas consulting firm. No director, officer, or key employee of CG&A has any financial ownership in us or any of our affiliates. CG&A’s compensation for the preparation of its report is not contingent upon the results obtained and reported. CG&A has not performed other work for us or any of our affiliates that would affect its objectivity. The estimates of our proved reserves presented in the CG&A reserve report were overseen by Todd Brooker.

Mr. Brooker is the President of CG&A and has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron Corporation. Mr. Brooker’s experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.

Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and the Society of Petroleum Evaluation Engineers.

Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure associated with the estimated proved reserves attributable to our properties as of December 31, 2020, based on the prepared reserve report by CG&A, our independent reserve engineers. The standardized measure shown in the table is not intended to represent the current market value of our estimated oil and natural gas reserves.

 

Reserves

 

 

Oil

 

 

Natural Gas

 

 

NGLs

 

 

Total

 

 

(MBbls)

 

 

(MMcf)

 

 

(MBbls)

 

 

(MBoe) (1)

 

Estimated Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

35,613

 

 

 

252,218

 

 

 

19,009

 

 

 

96,658

 

Undeveloped

 

11,063

 

 

 

21,921

 

 

 

2,475

 

 

 

17,191

 

Total

 

46,676

 

 

 

274,139

 

 

 

21,484

 

 

 

113,849

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves as a percentage of total proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

85

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Standardized measure (in thousands) (2)

 

 

 

 

 

 

 

 

 

 

 

 

$

298

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and Natural Gas Prices (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil – WTI per Bbl

 

 

 

 

 

 

 

 

 

 

 

 

$

39.57

 

Natural gas – Henry Hub per MMBtu

 

 

 

 

 

 

 

 

 

 

 

 

$

1.99

 

 

 

(1)

Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

(2)

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest expense, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions. For a description of our commodity derivative contracts, see “Item 1. Business — Operations — Derivative Activities” as well as “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Commodity Derivative Contracts.”

14


 

(3)

Our estimated net proved reserves and related standardized measure were determined using 12-month trailing average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month in effect as of the date of the estimate, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated reserves and future production rates are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by the SEC and FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

As of December 31, 2020, we had 17.2 MMBoe of proved undeveloped reserves comprised of 11.1 MMBbls of oil, 21.9 Bcfe of natural gas and 2.5 MMBbls of NGLs. None of our proved undeveloped reserves (“PUDs”) as of December 31, 2020 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2020 were due to:

 

Reserve adds of 0.2 MMBoe;

 

Reserve drops including price revisions of 15.8 MMBoe; and

 

Performance revisions including royalty relief of 0.5 MMBoe.

Approximately 0.4% (0.1 MMBoe) of our PUDs recorded as of December 31, 2019 were developed during the twelve months ended December 31, 2020. Total costs incurred to develop these PUDs were approximately $0.7 million, all of which was incurred in fiscal year 2020. In total, we incurred total capital expenditures of approximately $3.3 million during fiscal year 2020 developing PUDs, which includes $2.6 million associated with PUDs to be completed in 2021. Based on our current expectations of our cash flows, we believe that we can fund the drilling of our current PUD inventory and our expansions in the next five years from our cash flow from operations and borrowings under our Revolving Credit Facility. For a more detailed discussion of our liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Reserves sensitivity

Historically, commodity prices have been extremely volatile and due to the changes in the market with the impact of COVID-19, we expect this volatility to continue for the foreseeable future. For example, for the five years ended December 31, 2020, the NYMEX-WTI oil future price ranged from a high of $76.41 per Bbl to a low of $(37.63) per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $4.84 per MMBtu to a low of $1.48 per MMBtu. For the year ended December 31, 2020, the WTI posted price ranged from a high of $63.27 per Bbl on January 6, 2020 to a low of $(37.63) per Bbl on April 20, 2020 and the NYMEX-Henry Hub market price ranged from a high of $3.35 per MMBtu on October 30, 2020 to a low of $1.48 per MMBtu on June 25, 2020. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

The following sensitivity is provided to illustrate the value of our proved developed reserves at pricing that is more representative of the current market. Our year end proved developed standardized measure at SEC pricing was $239.2 million. With an oil price of $50.00 and natural gas price of $2.70 our proved developed standardized measure would increase to $566.2 million. There is no assurance that these prices will actually be achieved.

Production, Revenue and Price History

For a description of our and Legacy Amplify’s historical production, revenues, and average sales prices and per unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

15


The following tables summarize our average net production, average unhedged sales prices by product and average production costs (not including ad valorem and severance taxes) by geographic region for the years ended December 31, 2020 and 2019, respectively:

 

 

For the Year Ended December 31, 2020

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MBoe)

 

 

($/Boe)

 

 

($/Boe)

 

Oklahoma

 

687

 

 

$

36.84

 

 

 

857

 

 

$

10.75

 

 

 

9,395

 

 

$

0.93

 

 

 

3,109

 

 

$

13.90

 

 

$

6.14

 

Rockies

 

1,493

 

 

 

34.55

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,493

 

 

 

34.55

 

 

 

28.84

 

California

 

1,255

 

 

 

36.10

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,255

 

 

 

36.10

 

 

 

27.98

 

East Texas/ North Louisiana

 

198

 

 

 

35.37

 

 

 

836

 

 

 

12.52

 

 

 

17,905

 

 

 

1.87

 

 

 

4,018

 

 

 

12.68

 

 

 

4.33

 

Eagle Ford

 

254

 

 

 

35.75

 

 

 

32

 

 

 

11.99

 

 

 

173

 

 

 

2.01

 

 

 

315

 

 

 

31.14

 

 

 

16.05

 

Total

 

3,887

 

 

$

35.58

 

 

 

1,725

 

 

$

11.63

 

 

 

27,473

 

 

$

1.55

 

 

 

10,190

 

 

$

19.71

 

 

$

11.75

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net production (MBoe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

27.8

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2019

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MBoe)

 

 

($/Boe)

 

 

($/Boe)

 

Oklahoma

 

372

 

 

$

54.81

 

 

 

439

 

 

$

14.14

 

 

 

4,822

 

 

$

0.95

 

 

 

1,614

 

 

$

19.30

 

 

$

6.72

 

Rockies

 

1,381

 

 

 

50.72

 

 

 

63

 

 

 

38.80

 

 

 

 

 

 

 

 

 

1,445

 

 

$

50.20

 

 

$

30.49

 

California

 

1,132

 

 

 

58.38

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,132

 

 

 

58.38

 

 

 

39.63

 

East Texas/ North Louisiana

 

218

 

 

 

55.77

 

 

 

812

 

 

 

16.35

 

 

 

21,495

 

 

 

2.52

 

 

 

4,612

 

 

 

17.28

 

 

 

4.40

 

Eagle Ford

 

395

 

 

 

61.44

 

 

 

29

 

 

 

14.31

 

 

 

172

 

 

 

2.81

 

 

 

453

 

 

 

55.59

 

 

 

8.56

 

Total

 

3,498

 

 

$

55.16

 

 

 

1,343

 

 

$

16.64