ampy-10k_20201231.htm
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10–K
For the fiscal year ended December 31, 2020
OR
For the transition period from to .
Commission File Number: 001-35512
AMPLIFY ENERGY CORP.
(Exact name of registrant as specified in its charter)
(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 6. Selected Financial Data 48
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 62
Item 8. Financial Statements and Supplementary Data 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 14. Principal Accountant Fees and Services 64
PART IV
Item 15. Exhibits, Financial Statement Schedules 65
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:
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;
• ability to access capital markets;
• marketing of oil, natural gas and NGLs;
• 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;
• 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;
• our ability to satisfy our debt obligations;
• potential difficulties in the marketing of oil and natural gas;
• changes to the financial condition of counterparties;
• competition in the oil and natural gas industry;
• 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:
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:
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:
(in millions) (Years)
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
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
14
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)
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)
Average net production (MBoe/d) 25.4
Productive Wells
Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2020.
Oil Natural Gas
Gross Net Gross Net
16
Developed Acreage
Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2020, substantially all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2020 relating to our leasehold acreage.
Region Developed Acreage (1)
Gross (2) Net (3)
Undeveloped Acreage
The following table sets forth information as of December 31, 2020 relating to our undeveloped leasehold acreage (including the remaining terms of leases and concessions).
Undeveloped Net Acreage Subject to
Region Acreage Lease Expiration by Year
East Texas/ North Louisiana — — 18 —
Drilling Activities
Our drilling activities primarily consist of development wells. The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. At December 31, 2020, 48 gross (1 net) wells were in various stages of completion.
For the Year Ended December 31,
Gross Net Gross Net
Development wells:
Dry — — — —
Exploratory wells:
Productive — — — —
Dry — — — —
Total wells:
Dry — — — —
Delivery Commitments
We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existing sales contracts.
17
We have entered into a long-term gas gathering agreement associated with a certain portion of our East Texas production with a third-party midstream service provider that has volumetric requirements. We also have a long-term contract associated with our NGL production in Oklahoma that is subject to a volume obligation. Information regarding our delivery commitments under these contractsis contained in Note 16 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data,” contained herein.
Operations
General
As of December 31, 2020, the Company is the operator of record of properties containing 92% of our total estimated proved reserves. We design and manage the development, recompletion and/or workover operations, and supervise other operation and maintenance activities, for all of the wells we operate. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on our onshore properties; independent contractors provide all the equipment and personnel associated with these activities. Our Beta platforms have permanent drilling systems in place.
Marketing and Major Customers
The following individual customers each accounted for 10% or more of our total reported revenues for the period indicated:
For the Year Ended
December 31,
Major customers:
Sinclair Oil & Gas Company 21% 21%
BP America Production Company 17% 13%
The production sales agreements covering our properties contain customary terms and conditions for the oil and natural gas industry and provide for sales based on prevailing market prices. A majority of those agreements have terms that renew on a month-to-month basis until either party gives advance written notice of termination.
If we were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether and we were unable to replace them, the loss of any such customer could have a detrimental effect on our production volumes and revenues in general.
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with industry standards. More thorough title investigations are customarily made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests.
Derivative Activities
We enter into commodity derivative contracts with unaffiliated third parties, generally lenders under our Revolving Credit Facility or their affiliates, to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 30% - 60% of our estimated production from total proved developed producing reserves over a one-to-three-year period at any given point of time. Additionally, to satisfy the hedging covenants in our Revolving Credit Facility, we are expected to hedge 65% and 45% of our estimated production from total proved developed reserves for calendar years 2021 and 2022, respectively. We may, however, from time to time, hedge more or less than this approximate amount.
Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our Revolving Credit Facility) to fixed interest rates.
It is our policy to enter into derivative contracts only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our Revolving Credit Facility are counterparties to our derivative contracts. We will continue to evaluate the benefit of employing derivatives in the future.
18
Competition
We operate in a highly competitive environment for acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us.
Seasonal Nature of Business
The price we receive for our natural gas production is impacted by seasonal fluctuations in demand for natural gas. The demand for natural gas typically peaks during the coldest months and tapers off during the milder months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
Hydraulic Fracturing
We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete, except in our offshore wells. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. Our proved non-producing and proved undeveloped reserves make up 22.7% of the total proved reserves with approximately 57% of these requiring hydraulic fracturing as of December 31, 2020.
We believe we have followed and continue to substantially follow applicable industry standard practices and legal and regulatory requirements for groundwater protection in our hydraulic fracturing operations which are subject to supervision by state and federal regulators (including the U.S. Bureau of Land Management (the “BLM”) on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design is intended to essentially eliminate a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.
Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abnormal change occurred to the injection pressure or annular pressure.
Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand, and the fluids are managed and used in accordance with applicable requirements.
Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it into approved disposal or injection wells. We currently do not discharge water to the surface.
For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, see “— Environmental, Occupational Health and Safety Matters and Regulations — Hydraulic Fracturing.”
19
Insurance
In accordance with customary industry practice, we maintain insurance against many, but not all, potential losses or liabilities arising from our operations and at costs that we believe to be economic. We regularly review our risks of loss and the cost and availability of insurance and revise our insurance accordingly. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses. We currently have insurance policies that include the following:
• Commercial General Liability; • Oil Pollution Act Liability;
• Primary Umbrella / Excess Liability; • Pollution Legal Liability;
• Property; • Charterer’s Legal Liability;
• Workers’ Compensation; • Non-Owned Aircraft Liability;
• Employer’s Liability; • Automobile Liability;
• Maritime Employer’s Liability; • Directors & Officers Liability;
• U.S. Longshore and Harbor Workers’; • Employment Practices Liability;
• Energy Package/Control of Well; • Crime; and
• Loss of Production Income (offshore only); • Fiduciary Liability.
We continuously monitor regulatory changes and comments and consider their impact on the insurance market, along with and our overall risk profile. As necessary, we will adjust our risk and insurance program to provide protection at a level we consider appropriate, while weighing the cost of insurance against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations could lead to changes in underwriting standards, limitations on scope and amount of coverage, and higher premiums, including possible increases in liability caps for claims of damages from oil spills.
Environmental, Occupational Health and Safety Matters and Regulations
General
Our oil and natural gas development and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. In addition, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. New laws and regulations continue to be enacted, particularly at the state level, and, under the Biden Administration, the long-term trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
The following is a summary of the more significant existing environmental, occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
20
BOEM & BSEE
Our oil and gas operations associated with our Beta Properties are conducted on offshore leases in federal waters. The Bureau of Ocean Energy Management (“BOEM”) and the BSEE have broad authority to regulate our oil and gas operations associated with our Beta Properties.
BOEM is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act (“NEPA”) analysis and environmental studies. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. In October 2020, BOEM and BSEE issued a proposed rule to clarify, streamline, and provide greater transparency to financial assurance requirements, including streamlining the evaluation criteria for determining if and when additional security is required for Outer Continental Shelf (“OCS”) leases, pipeline rights-of-way and rights-of-use and easement and revising the process for issuing decommissioning obligations for facilities on the OCS. The new criteria may require lessees or operators to take additional steps to demonstrate that they have the financial ability to carry out their lease obligations. It is unclear whether BOEM and BSEE will finalize this rule under the Biden Administration.
BSEE is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and training and environmental compliance programs. BSEE regulations require offshore production facilities and pipelines located on the OCS to meet stringent engineering and construction specifications, and BSEE has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas, prohibit the flaring of liquid hydrocarbons and govern the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities.
BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta Properties be suspended or terminated and we may be subject to civil or criminal liability.
In November 2018, a federal court prohibited BOEM and BSEE from approving any plans or issuing permits involving hydraulic fracturing and/or acid well stimulation on the Pacific OCS until the agencies complete consultation with the U.S. Fish and Wildlife Service under the Endangered Species Act (the “ESA”) and submit a consistency determination under the Coastal Zone Management Act to the California Coastal Commission. Although we do not use either hydraulic fracturing or acid stimulation routinely in connection with our operations on the Beta Properties, delays in the approval or refusal of plans and issuance of permits by BOEM or BSEE because of staffing, economic, environmental, legal or other reasons (or other actions taken by BOEM or BSEE) could adversely affect our offshore operations. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations. Also, in addition to permits and approvals required by BOEM and BSEE, approvals and permits are required from other agencies for the oil and gas operations associated with our Beta Properties, such as the U.S. Coast Guard, the EPA, U.S. Department of Transportation and the South Coast Air Quality Management District.
21
Hazardous Substances and Waste Handling
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also referred to as the Superfund law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Also, comparable state statutes may not contain a similar exemption for petroleum, and it is also not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.
The Oil Pollution Act of 1990 (“OPA”) is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills. For example, the California Department of Fish and Wildlife’s Office of Oil Spill Prevention and Response have adopted oil-spill prevention regulations that overlap with federal regulations.
We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA entered into a consent decree requiring it to review its regulation of oil and gas waste. In April 2019, the EPA determined that revisions to the RCRA regulations were not required, concluding that any adverse effects related to oil and gas waste are more appropriately and readily addressed within the framework of existing state regulatory programs. However, any such changes to state programs could result in an increase in our costs to manage and dispose of oil and gas waste, which could have a material adverse effect on our maintenance capital expenditures and operating expenses.
It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials (“NORM”). NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes into contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.
Administrative, civil and criminal penalties can be imposed for failure to comply with hazardous substance and waste handling requirements. We believe that we are in substantial compliance with the requirements of CERCLA, OPA, RCRA, and other applicable federal and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our hazardous substances and wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
22
Water Discharges
The Federal Water Pollution Control Act (the “Clean Water Act”), the Safe Drinking Water Act (“SDWA”), the OPA and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). In June 2015, the EPA and the Corps issued a rule to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, which was repealed by the EPA on October 22, 2019 and became effective in December 2019. In January 2020, the EPA and the Corps announced the final rule, the Navigable Water Protection Rule (“NWPR”), revising the definition of WOTUS, which was published in April 2020 and went into effect in June 2020. The new definition narrows the scope of waters that are covered as jurisdictional. Several groups have already challenged the NWPR. At President Biden’s direction, the EPA and the Corps requested the litigation be stayed while the agencies review the NWPR. As a result, future implementation is uncertain at this time. To the extent a stay of this rule or the implementation of a revised rule expands the scope of the Clean Water Act's jurisdiction, or impacts available agency resources, the Company could face increased costs and/or delays with respect to obtaining permits for dredge and fill activities in wetland areas.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of storm water or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits or specify other requirements for discharges or operations that may impact groundwater conditions. These same regulatory programs may also limit the total volume of water that can be discharged, hence limiting the rate of development and requiring us to incur compliance costs. Additionally, we are required to develop and implement spill prevention, control and countermeasure plans, in connection with on-site storage of significant quantities of oil.
These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Additionally, obtaining permits has the potential to delay the development of natural gas and oil projects. We maintain all required discharge permits necessary to conduct our operations and we believe we are in substantial compliance with their terms.
In addition, in some instances, the operation of underground injection wells for the disposal of wastewater has been alleged to cause earthquakes. For example, in February 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. In some jurisdictions, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity or resulted in stricter regulatory requirements relating to the location and operation of underground injection wells. Such issues have also led to lawsuits by private parties alleging damages relating to induced seismicity. For example, the Railroad Commission of Texas (the “Commission”) requires applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey, which are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The Commission is authorized to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Commission is also considering new restrictions that could limit the volume and pressure of produced water injected into disposal wells. Additionally, we conduct oil and gas drilling and production operations in the Mississippian Lime formation in Oklahoma, a high-water play, which requires us to dispose of large volumes of saltwater generated as part of our operations. In 2015, the Oklahoma Geological Survey attributed an increase in seismic activity in Oklahoma to saltwater disposal wells in the Arbuckle formation. Around the same time, the Oklahoma Corporation Commission (“OCC”), whose Oil and Gas Conservation Division regulates oil and gas operations in Oklahoma, began issuing regulations targeting saltwater disposal activities in certain areas of interest within the Arbuckle formation. The regulations include operational requirements (i.e., mechanical integrity testing of wells permitted for disposal of 20,000 or more barrels of water per day, daily monitoring and recording of well pressure and discharge volume), as well as orders to shut-in wells, reduce well depths, or decrease disposal volumes. Under these regulations, in 2016 and 2017, the OCC ordered us to limit the volume of saltwater disposed of in saltwater disposal wells in the Arbuckle formation, and it established caps for ten of our saltwater disposal wells in February 2017. To ensure that we had an adequate number of wells for disposal, we secured permits for additional saltwater disposal wells outside of the Arbuckle formation. We timely satisfied all OCC saltwater disposal requirements, while maintaining our production base without any negative material impact. However, any future orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect or curtail our operations.
23
Hydraulic Fracturing
We use hydraulic fracturing extensively in our onshore operations, but not our offshore operations. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. In June 2016, the EPA finalized wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works. In July 2019, after a legal challenge by environmental groups, the EPA declined to revise these rules, and, for certain facilities, compliance was required by August 2019. This restriction of disposal options for hydraulic fracturing waste and other changes to environmental requirements may result in increased costs.
In addition, in March 2015, the BLM published a final rule governing hydraulic fracturing on federal and Indian lands. The rule required public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures and the depths of all usable water. Following years of litigation, the BLM rescinded the rule in December 2017. However, several environmental groups and states have challenged the BLM’s rescission of the rule in ongoing litigation.
Several states have also adopted, or are considering adopting, regulations requiring the disclosure of the chemicals used in hydraulic fracturing and/or otherwise imposing additional requirements for hydraulic fracturing activities. For example, Oklahoma requires oil and gas producers to report the chemicals they use in hydraulic fracturing to FracFocus.org, a national hydraulic fracturing chemical registry, or to the OCC, which will convey the information to FracFocus.org. The Louisiana Department of Natural Resources has adopted rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, Texas requires oil and natural gas operators to disclose to the Commission and the public the chemicals used in the hydraulic fracturing process, as well as the total volume of water used. Texas has also imposed requirements for drilling, putting pipe down and cementing wells, and testing and reporting requirements.
Certain governmental reviews have been conducted that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, in December 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. The EPA has also issued a draft study of onshore conventional and unconventional oil and gas extraction wastewater management, and conducted a study of private wastewater treatment facilities, also known as centralized waste treatment facilities, accepting oil and gas extraction wastewater. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated various other aspects of hydraulic fracturing. In addition, as discussed above, BOEM and BSEE completed a study in May 2016 regarding the potential environmental impacts of well-stimulation practices on the Pacific OCS. These studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Additionally, a number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. We believe that we follow standard industry practices and legal requirements applicable to our hydraulic fracturing activities. Nonetheless, in the event of new or more stringent federal, state or local legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater or otherwise have negative impacts.
24
In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. For example, the U.S. Congress has from time to time considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
Air Emissions
The federal Clean Air Act, as amended (“CAA”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. The South Coast Air Quality Management District (“SCAQMD”) is a regulatory subdivision of the State of California and responsible for air pollution control from stationary sources within Orange County and designated portions of Los Angeles, Riverside, and San Bernardino Counties. Our Beta Properties and associated facilities are subject to regulation by the SCAQMD. Federal, SCAQMD, and other state laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.
The New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs under the CAA impose specific requirements affecting the oil and gas industry for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants, completions and certain other equipment. Periodic review and revision of these rules by federal and state agencies may require changes to our operations, including possible installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business. For example, in August 2019, the EPA issued a proposed rule to rescind the methane requirements for certain sources in the production and processing segments of the oil and gas industry; the rulemaking, known as the Reconsideration Rule, was finalized in September 2020. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration rule by September 2021. Separately, in September 2020, the EPA finalized the Review Rule rescinding requirements related to the regulations of methane emissions from the oil and natural gas industry. Both rules are subject to ongoing litigation; therefore, the scope of future obligations continues to remain uncertain. Similarly, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of regulations it previously enacted to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands; this rule was invalidated in federal district court. Any future changes to the NSPS and NESHAP programs, and other air quality programs, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs and could adversely impact our business.
We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.
Regulation of “Greenhouse Gas” Emissions
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. For example, the EPA, as well as the BLM, have issued rules to reduce methane emissions from oil and natural gas production and processing operations, which regulations are discussed in more detail above under the caption “Air Emissions.” Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, the EPA has adopted regulations requiring the monitoring and annual reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which include certain of our operations. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
25
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of states have taken legal measures to reduce emissions of GHGs, including through the planned development of GHGs emission inventories and/or regional GHGs cap and trade programs. In addition, on an international level, the United States was one of nearly 200 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emission reduction goals beginning in 2020. However, the United States formally announced its intent to withdraw from the Paris Agreement in November 2019, which became effective in November 2020. On January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which will become effective on February 19, 2021. In addition, various states and local governments vowed to continue to enact regulations to achieve the goals of the Paris Agreement.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. Any GHG regulation could increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.
In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance or have caused other redressable injuries under federal and/or state common law. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations.
Moreover, any legislation or regulatory programs to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities. Finally, it should be noted that most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our development and production operations.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the U.S. Departments of the Interior and Agriculture, to evaluate major federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency typically evaluates the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a detailed environmental impact statement that is made available for public review and comment. In July 2020, the White House’s Council on Environmental Quality published a final rule to amend the NEPA implementing regulations intended to streamline the environmental review process, including shortening the time for review as well as eliminating the requirement to evaluate cumulative impacts. The new regulations are subject to ongoing litigation in several federal districts and thus potential impacts of this rule on our business are uncertain at this time. All of our current development and production activities, as well as proposed development plans, on federal lands, including those in the Pacific Ocean, require governmental permits that are subject to the requirements of NEPA. This environmental review process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.
26
Endangered Species Act and Migratory Bird Treaty Act
The federal ESA and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. In August 2019, the U.S. Fish and Wildlife Service (the “FWS”) and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged these rules and the litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations. We anticipate the rule will be subject to litigation. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”) , which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA, however the Department of the Interior under President Biden delayed the effective date of the rule and opened a public comment period for further review. Future implementation of the rules implementing the ESA and the MBTA are uncertain. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position.
Occupational Safety and Health Act
We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. For example, under a new OSHA standard limiting respirable silica exposure, the oil and gas industry must implement engineering controls and work practices to limit exposures below the new limits by June 2021. Failure to comply with OSHA requirements can lead to the imposition of penalties. We believe that our operations are in substantial compliance with the OSHA requirements.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on our assets. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress, and the development of regulations continues in the U.S. Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Drilling and Production
Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
• the location of wells;
• the method of drilling and casing wells;
• the surface use and restoration of properties upon which wells are drilled;
• the plugging and abandoning of wells;
• transportation and disposal of produced fluids and natural gas; and
• notice to surface owners and other third parties.
27
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
Sale and Transportation of Gas and Oil
The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the construction and operations of interstate gas pipeline facilities and the rates terms and conditions of service under which companies provide interstate transportation of gas, oil and other liquids by pipeline. Although the FERC does not have jurisdiction over the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. These agency actions have been intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.
The FERC and other federal agencies, the U.S. Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any such proposal will affect us any differently than it would affect other gas or oil producers with which we compete.
The Beta Properties include the San Pedro Bay Pipeline Company, which owns and operates an offshore crude oil pipeline. This pipeline is subject to regulation by the FERC under the Interstate Commerce Act and the Energy Policy Act of 1992. Tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, must be just and reasonable and not unduly-discriminatory. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly. The FERC has established a formulaic methodology for oil and liquids pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Effective July 1, 2016, the current index for the five-year period ending July 2021 is the producer price index for finished goods plus an adjustment factor of 1.23 percent. The San Pedro Bay Pipeline Company uses the indexing methodology to change its rates.
The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. BOEM/BSEE has established formal and informal complaint procedures for shippers that believe they have been denied open and nondiscriminatory access to transportation on the OCS.
The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates the safety of all pipeline transportation in or affecting interstate or foreign commerce, including pipeline facilities on the OCS. The San Pedro Bay pipeline is subject to regulation by the PHMSA. In recent years, PHMSA has been active in proposing and finalizing additional regulations for natural gas and hazardous liquids pipelines. For example, in January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to a high consequence areas (“HCA”). The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure. In addition, in April 2016, PHMSA proposed a rule regarding the safety of natural gas transmission pipelines and gas gathering pipelines. In October 2019, PHMSA issued a final rule on the natural gas transmission lines portion of the April 2016 rulemaking, but PHMSA has not yet issued a final rule on the gathering lines portion of the April 2016 rulemaking. If the pending gathering-pipeline portion of the rulemaking ultimately includes a final rule that applies similar requirements to gathering lines as the final rule for natural gas transmission lines, some gathering pipeline operators may be forced to reduce their allowable operating pressures, which would reduce the amount of capacity available to the Company. As PHMSA has yet to finalize this rulemaking as applied to gathering lines, however, it is uncertain what impact the final rule may have on the Company.
28
Moreover, effective April 2017, the PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations. PHMSA updates the maximum administrative civil penalties each year to account for inflation, and as of January 2021, the penalty limits are up to $222,504 per violation per day and up to $2,225,034 for a related series of violations. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulation. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
Anti-Market Manipulation Laws and Regulations
The FERC with respect to the purchase or sale of natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction and the Federal Trade Commission with respect to petroleum and petroleum products, operating under various statutes have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order repayment or disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Derivatives Regulation
Comprehensive financial reform legislation was signed into law by the President on July 21, 2010 (“Dodd-Frank Act”). This legislation called for the Commodities Futures Trading Commission (“CFTC”) to regulate certain markets for derivative products, including over-the-counter derivatives. The CFTC has issued several new relevant regulations and rulemakings to implement Dodd-Frank Act the mandate to cause significant portions of derivatives markets to clear through clearinghouses, along with other mandated changes. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.
In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The CFTC’s final rules were challenged in court by two industry associations and were vacated and remanded by a federal district court. Subsequently, the CFTC proposed new rules in November 2013 and December 2016. In January 2020, the CFTC withdrew the 2013 and 2016 proposals, and issued a new proposed rule, which includes limits on positions in (1) certain “Core Referenced Futures Contracts,” including contracts for several energy commodities; (2) futures and options on futures that are directly or indirectly linked to the price of a Core Referenced Futures Contract, or to the same commodity for delivery at the same location as specified in that Core Referenced Futures Contract; and (3) economically equivalent swaps. The proposal also includes exemptions from position limits for bona fide hedging activities. The proposal is not yet final, and it remains subject to public comment and subsequent revision by the CFTC. Consequently, the impact of the proposed rule on the Company and its counterparties is uncertain at this time.
The Dodd-Frank Act and new, related regulations may prompt counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may become less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations. Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.
Our sales of oil and natural gas are also subject to anti-manipulation and anti-disruptive practices authority under (i) the Commodity Exchange Act (“CEA”), as amended by the Dodd-Frank Act, and regulations promulgated thereunder by the CFTC, and (ii) the Energy Independence and Security Act of 2007 (“EISA”) and regulations promulgated thereunder by the FTC. The CEA, as amended by the Dodd-Frank Act, prohibits any person from using or employing any manipulative or deceptive device in connection with any swap, or a contract for sale of any commodity, or for future delivery on such commodity, in contravention of the CFTC’s rules and regulations. It also prohibits knowingly delivering or causing to be delivered false, misleading or inaccurate reports concerning market information or conditions that affect or tend to affect the price of any commodity. The FTC’s Petroleum Market Manipulation Rule, issued pursuant to EISA, prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. Under both the CEA and the EISA, fines for violations can be up to $1,000,000 per day per violation (subject to adjustment for inflation) and certain knowing or willful violations may also lead to a felony conviction.
29
Additional proposals and proceedings that may affect the crude oil and natural gas industry are pending before the U.S. Congress, federal agencies and the courts. The Company cannot predict the ultimate impact these proposals may have on its crude oil and natural gas operations, but the Company does not expect any such action to affect the Company differently than it will affect other gas or oil producers with which we compete.
State Regulation
Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, the baseline Texas severance tax on oil and gas is 4.6% of the market value of oil produced and 7.5% of the market value of gas produced and saved. A number of exemptions from or reductions of the severance tax on oil and gas production is provided by the State of Texas which effectively lowers the cost of production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Human Capital
Employees and Labor Relations
At December 31, 2020, the Company had 189 employees, none of whom are represented by labor unions or covered by any collective bargaining agreement. We strive to create a high-performing culture and positive work environment that allows us to attract and retain a diverse group of talented individuals who can foster the Company’s success. To attract and retain top talent, our human resources programs are designed to reward and incentivize our employees through competitive compensation practices, our commitment to employee health and safety, training and talent development and commitment to diversity and inclusion.
Compensation
We operate in a highly competitive environment and have designed our compensation program to attract, retain and motivate talented and experienced individuals. Our compensation philosophy is designed to align our workforce’s interests with those of our stakeholders and to reward them for achieving the Company’s business and strategic objectives and driving shareholder value. We consider competitive market compensation paid by our peers and other companies comparable to the us in size, geographic location and operations in order to ensure compensation remains competitive and fulfills our goal of recruiting and retaining talented employees.
Safety
Safety is our highest priority, and we are dedicated to the wellbeing of our employees, contractors, business partners, stakeholders and the environment. We promote safety with a robust health and safety program, which includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective and preventative action development.
In addition, we employ environmental, health and safety personnel at each of our asset locations, who provide in-person safety training and regular safety meetings. We also utilize learning management software to provide safety training on a variety of topics, and we contract with third-party technical experts, as needed, to facilitate training on specialized topics that are unique to each of our areas of operation. Our Total Recordable Incident Rate (TRIR), a commonly used safety metric that normalizes injury rates among Company employees and contractors across companies of all sizes, has decreased from 0.34 in 2019 to zero in 2020. This is directly attributable to the Company’s and its employees’ commitment to and focus on safety.
Health and Wellness
We support our employees and their families by offering a robust package of health and welfare benefits, medical, dental, and vision insurance plans for employees and their families, life insurance and long-term disability plans, paid time off for holidays, vacation, sick leave, and other personal leave, and health and dependent care savings accounts. We also provide our employees with a 401(k) plan that includes a competitive company match, and employees have access to a variety of resources and services to help them plan for retirement.
In addition to these programs, we have several other programs designed to further promote the health and wellness of our employees, as well as an employee assistance program that offers counseling and referral services for a broad range of personal and family situations.
30
In response to the COVID-19 pandemic, commencing in the first quarter of 2020, we implemented proactive measures to protect the health and safety of our employees. These measures have includedimplementation of a COVID-19 leave program to allow employees to take time off when they or their family members contract COVID-19, implementation of health screenings, COVID-19 testing for our offshore workforce, allowing employees to work remotely to reduce the number of employees on site in our field areas to comply with social distancing guidelines, maintaining social distancing policies, requiring the use of masks in compliance with governmental mandates, frequently and extensively disinfecting common areas, performing contact tracing protocols, if and when necessary, and implementing quarantine requirements, among other things. We are committed to maintaining best practices with our COVID-19 response protocols and will continue to work under the guidance of public health officials to ensure a safe workplace as long as COVID-19 remains a threat to our employees and communities.
Training and Development
We are committed to the training and development of our employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We encourage our employees to advance their knowledge and skills and to network with other professionals in order to pursue career advancement and potential future opportunities with the Company. Our employees are able to attend training seminars and off-site workshops or to join professional associations that will enable them to remain up-to-date on the latest changes and best practices in their respective fields.
Diversity and Inclusion
We are committed to providing a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. We recognize that a diverse workforce provides the opportunity to obtain unique perspectives, experiences, ideas, and solutions to help our business succeed. To that end, we prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, national origin, age, disability, genetic information, veteran status, or any other basis protected by federal, state or local law. Further, we forbid retaliation against any individual who reports, claims, or makes a charge of discrimination or harassment, fraud, unethical conduct, or a violation of our Company policies. To sustain and promote an inclusive culture, we maintain a robust compliance program rooted in our Code of Business Conduct and Ethics and other Company policies, which provide policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities. We require all employees to complete periodic training sessions on various aspects of our corporate policies through an annual acknowledgement and certification process.
Offices
Our principal executive office is located at 500 Dallas Street, Suite 1700, Houston, Texas 77002. Our main telephone number is (713) 490-8900.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at www.amplifyenergy.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. Our website also includes our Code of Business Conduct and Ethics, Corporate Governance Guidelines and the charters of our audit committee, compensation committee and nominating & governance committee. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
The SEC maintains a website that contains reports, proxy and information statements, and other information regarding the Company at www.sec.gov.
31
ITEM 1A. RISK FACTORS
Our business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item 1. Business” of this annual report, may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price of our securities could decline and you could lose all or part of your investment.
Risks Related to Our Business
Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.
Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:
• the regional, domestic and foreign supply of oil, natural gas and NGLs;
• the level of commodity prices and expectations about future commodity prices;
• the level of global oil and natural gas exploration and production;
• the cost of exploring for developing, producing and transporting reserves;
• the price and quantity of foreign imports;
• political and economic conditions in oil producing countries;
• speculative trading in crude oil and natural gas derivative contracts;
• the level of consumer product demand;
• weather conditions and other natural disasters;
• risks associated with operating drilling rigs;
• domestic and foreign governmental regulations and taxes;
• the impact of energy conservation efforts;
• the continued threat of terrorism and the impact of military and other action;
• overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 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 prices 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 NYMEX-Henry Hub natural gas 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. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have sustained depressed realized prices during this period and are generally correlated with the price of oil. A further or extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition.
32
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.
As discussed above, oil, natural gas and NGL prices have experienced significant volatility over the past few years. A further or extended decline in commodity prices could render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to fund our operations.
We recognized $477.0 million and $2.2 million in impairment expense for the years ended December 31, 2020 and 2019, respectively. A further or extended decline in commodity prices may cause us to recognize additional impairments in the value of our oil and natural gas properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our Revolving Credit Facility.
The oversupply of oil and natural gas and lower demand caused by the 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.
In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the United States. The spread of COVID-19 has caused significant volatility in U.S. and international markets. There is significant uncertainty regarding the breadth and duration of business disruptions related to COVID-19, as well as its impact on the U.S. and international economies. The outbreak of COVID-19 in the United States and the uncertainty of its impact, has contributed to an unprecedented oversupply of and decline in demand for oil and natural gas. At this time, the full extent to which COVID-19 will negatively impact the global economy and our business is uncertain.
In addition, in March 2020, oil prices severely declined following unsuccessful negotiations between members of OPEC and certain nonmembers, including Russia, to implement production cuts in an effort to decrease the global oversupply and to rebalance supply and demand due to the ongoing COVID-19 pandemic. In April 2020, members of OPEC and Russia agreed to temporary production reductions, but uncertainty about whether such production cuts and/or the duration of such reductions will be sufficient to rebalance supply and demand remains and may continue for the foreseeable future.
To the extent that the COVID-19 pandemic continues to negatively impact demand and OPEC members and other oil exporting nations fail to take actions aimed at supporting and stabilizing commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period. This excess supply could, in turn, result in transportation and storage capacity constraints, as well as shut-ins and production curtailment in the United States. If, in the future, our transportation and/or storage capacity becomes constrained, we may be required to shut-in wells or curtail production, which may adversely affect our business, financial condition and results of operations.
In addition, uncertainties regarding the global economic and financial environment could lead to an extended national or global economic recession. A slowdown in economic activity caused by a recession would likely reduce national and worldwide demand for oil and natural gas and result in lower commodity prices. Costs of exploration, development and production have not yet adjusted to current economic conditions, or in proportion to the significant reduction in product prices.
Over the past several years, capital and credit markets for the oil and natural gas industry have experienced volatility and disruption. Further market volatility and disruption and concerns regarding borrower solvency may substantially diminish the availability of funds from those markets, increase the cost of accessing the credit markets, subject borrowers to stricter lending standards, or may cause lenders to cease providing funding to borrowers, any of which may 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.
The COVID-19 pandemic has negatively impacted, and may continue to negatively impact, the global economy which has led to, among other things, reduced global demand for oil and natural gas and significant volatility and disruption of financial and commodity markets.
We experienced substantial decreases in our revenues in the first quarter of 2020, which negatively impacted our business, financial condition, results of operations, cash flows and outlook during 2020. The adverse effects of COVID-19 included or may in the future include the following:
• Historically low crude oil prices;
• Curtailment or shutting in of production;
33
• Delay or cessation of workover projects;
• Insufficient production to satisfy transportation and processing commitments;
• Impairment of assets;
• Reductions in the borrowing base of our Revolving Credit Facility;
• Limitations on the ability to market our production;
The extent to which COVID-19 and depressed commodity price impact our results of operations, financial position and liquidity will depend on future developments, which are uncertain and cannot be predicted, including but not limited to, the availability of effective treatments and vaccines, the ultimate duration of the pandemic, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, the degree and duration of the adverse financial impact of the pandemic cannot be reasonably estimated at this time.
We may be unable to maintain compliance with the covenants in the Revolving Credit Facility, which could result in an event of default thereunder that, if not cured or waived, would have a material adverse effect on our business and financial condition.
Under our Revolving Credit Facility, we are required to maintain (i) as of the date of determination, a maximum total debt to EBITDAX ratio of 4.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) maintain a minimum hedging requirement to at least 30%-60% of our estimated production from total proved developed producing reserves. If we were to violate any of the covenants under the Revolving Credit Facility and were unable to obtain a waiver or amendment, it would be considered a default after the expiration of any applicable grace period. If we were in default under the Revolving Credit Facility, then the lenders may exercise certain remedies including, among others, declaring all borrowings outstanding thereunder, if any, immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due, because we might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Revolving Credit Facility are secured by mortgages on not less than 90% of the PV-9 value of our oil and gas properties (and at least 90% of the PV-9 value of the proved, developed and producing oil and gas properties), and if we are unable to repay our indebtedness under our Revolving Credit Facility, the lenders could seek to foreclose on our assets.
Restrictive covenants in our Revolving Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Restrictive covenants in our Revolving Credit Facility impose significant operating and financial restrictions on us and our subsidiaries. These restrictions limit our ability to, among other things:
• incur additional liens;
• incur additional indebtedness;
• merge, consolidate or sell our assets;
• pay dividends or make other distributions or repurchase or redeem our stock;
• make certain investments; and
• enter into transactions with our affiliates.
The Revolving Credit Facility also requires us to comply with certain financial maintenance covenants as discussed above. A breach of any of these covenants could result in a default under the Revolving Credit Facility. If a default occurs and remains uncured or unwaived, the administrative agent or majority lenders under the Revolving Credit Facility may elect to declare all borrowings outstanding thereunder, if any, together with accrued interest and other fees, to be immediately due and payable. The administrative agent or majority lenders under the Revolving Credit Facility would also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay our indebtedness when due or declared due, the administrative agent will also have the right to proceed against the collateral pledged to it to secure the indebtedness under the Revolving Credit Facility. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.
34
We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants in the Revolving Credit Facility. The terms and conditions of the Revolving Credit Facility affect us in several ways, including:
• limiting management’s discretion in operating our business.
Our lenders periodically redetermine the amount we may borrow under our Revolving Credit Facility, which may materially impact our operations.
Our Revolving Credit Facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Accordingly, declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute on our business plans. Any reduction in the borrowing base would materially and adversely affect our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations. In addition, as hedges roll off, the borrowing base is subject to further reduction. Our Revolving Credit Facility requires us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of notice to do so. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the Revolving Credit Facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under the Revolving Credit Facility.