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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to .
Commission File Number:
(Exact name of registrant as specified in its charter)
| ||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (
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.
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).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large 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 is a shell company (as defined in Rule 12b–2 of the Exchange Act). Yes
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 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. þ Yes ☐ No
Securities Registered Pursuant to Section 12(b):
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
As of July 29, 2022, the registrant had
AMPLIFY ENERGY CORP.
TABLE OF CONTENTS
|
| Page | ||
1 | ||||
4 | ||||
5 | ||||
Item 1. | 8 | |||
Unaudited Condensed Consolidated Balance Sheets as of June 30, 2022 and December 31, 2021 | 8 | |||
9 | ||||
10 | ||||
11 | ||||
Notes to Unaudited Condensed Consolidated Financial Statements | 12 | |||
12 | ||||
13 | ||||
13 | ||||
14 | ||||
15 | ||||
18 | ||||
19 | ||||
20 | ||||
21 | ||||
21 | ||||
24 | ||||
26 | ||||
27 | ||||
27 | ||||
28 | ||||
28 | ||||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 32 | ||
Item 3. | 42 | |||
Item 4. | 43 | |||
Item 1. | 44 | |||
Item 1A. | 44 | |||
Item 2. | 44 | |||
Item 3. | 44 | |||
Item 4. | 44 | |||
Item 5. | 44 | |||
Item 6. | 45 | |||
46 | ||||
i
GLOSSARY OF OIL AND NATURAL GAS TERMS
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.
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.
BOEM: U.S. Bureau of Ocean Energy Management.
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.
CO2: Carbon dioxide.
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.
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.
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.
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 a working interest.
ICE: Inter-Continental Exchange.
MBbl: One thousand Bbls.
MBbls/d: One thousand Bbls per day.
MBoe: One thousand barrels of oil equivalent.
1
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.
Mcf/d: One Mcf per day.
MMBtu: One million Btu.
MMcf: One million cubic feet of natural gas.
MMcfe: One million cubic feet of natural gas equivalent.
MMcfe/d: One MMcfe per day.
Net Production: Production that is owned by us less royalties and production due to others.
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.
NYSE: New York Stock 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.
OPIS: Oil Price Information Service.
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.
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 occurrence.
Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
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
2
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.
Realized Price: The cash market price less all expected quality, transportation and demand adjustments.
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.
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.
SEC: The U.S. Securities and Exchange Commission
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 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.
3
NAMES OF ENTITIES
As used in this Form 10-Q, unless indicated otherwise:
| ● | “Amplify Energy,” “Company,” “we,” “our,” “us,” or like terms refers to Amplify Energy Corp. individually and collectively with its subsidiaries, as the context requires; |
| ● | “Legacy Amplify” refers to Amplify Energy Holdings LLC (f/k/a Amplify Energy Corp.), the successor reporting company of Memorial Production Partners LP; and |
| ● | “OLLC” refers to Amplify Energy Operating LLC, our wholly owned subsidiary through which we operate our properties. |
4
CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), 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; |
| ● | ongoing impact of the oil incident that occurred off the coast of Southern California resulting from our pipeline operations (the “Pipeline”) at the Beta Field (the “Incident”); |
| ● | acquisition and disposition strategy; |
| ● | cash flows and liquidity; |
| ● | financial strategy; |
| ● | ability to replace the reserves we produce through drilling; |
| ● | drilling locations; |
| ● | oil and natural gas reserves; |
| ● | technology; |
| ● | realized oil, natural gas and NGL prices; |
| ● | production volumes; |
| ● | lease operating expense; |
| ● | gathering, processing and transportation; |
| ● | general and administrative expense; |
| ● | future operating results; |
| ● | ability to procure drilling and production equipment; |
| ● | ability to procure oil field labor; |
| ● | planned capital expenditures and the availability of capital resources to fund capital expenditures; |
| ● | ability to access capital markets; |
| ● | marketing of oil, natural gas and NGLs; |
| ● | acts of God, fires, earthquakes, storms, floods, other adverse weather conditions, war, acts of terrorism, military operations or national emergency; |
| ● | the occurrence or threat of epidemic or pandemic diseases, including the coronavirus (“COVID-19”) pandemic, or any government response to such occurrence or threat; |
5
| ● | expectations regarding general economic conditions; |
| ● | competition in the oil and natural gas industry; |
| ● | effectiveness of risk management activities; |
| ● | environmental liabilities; |
| ● | counterparty credit risk; |
| ● | expectations regarding governmental regulation and taxation; |
| ● | expectations regarding developments in oil-producing and natural-gas producing countries; and |
| ● | plans, objectives, expectations and intentions. |
All statements, other than statements of historical fact included in this report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “would,” “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:
| ● | risks related to the Incident and the ongoing impact to the Incident; |
| ● | risks related to a redetermination of the borrowing base under our senior secured reserve-based revolving credit facility; |
| ● | our ability to access funds on acceptable terms, if at all, because of the terms and conditions governing our indebtedness, including financial covenants; |
| ● | our ability to satisfy debt obligations; |
| ● | volatility in the prices for oil, natural gas and NGLs, including further or sustained declines in commodity prices; |
| ● | the potential for additional impairments due to continuing or future declines in oil, natural gas and NGL prices; |
| ● | the uncertainty inherent in estimating quantities of oil, natural gas and NGLs reserves; |
| ● | our substantial future capital requirements, which may be subject to limited availability of financing; |
| ● | the uncertainty inherent in the development and production of oil and natural gas; |
| ● | our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base; |
| ● | the existence of unanticipated liabilities or problems relating to acquired or divested businesses or properties; |
| ● | potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties; |
| ● | the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity; |
6
| ● | potential shortages of, or increased costs for, drilling and production equipment and supply materials for production, such as CO2; |
| ● | potential difficulties in the marketing of oil and natural gas; |
| ● | changes to the financial condition of counterparties; |
| ● | uncertainties surrounding the success of our secondary and tertiary recovery efforts; |
| ● | competition in the oil and natural gas industry; |
| ● | our results of evaluation and implementation of strategic alternatives; |
| ● | general political and economic conditions, globally and in the jurisdictions in which we operate, including escalating tensions between Russia and Ukraine and the political destabilizing effect such conflict may pose for the European continent or the global oil and natural gas markets; |
| ● | the impact of climate change and natural disasters, such as earthquakes, tidal waves, mudslides, fires and floods; |
| ● | the impact of local, state and federal governmental regulations, including those related to climate change and hydraulic fracturing; |
| ● | the risk that our hedging strategy may be ineffective or may reduce our income; |
| ● | the cost and availability of insurance as well as operating risks that may not be covered by an effective indemnity or insurance; |
| ● | actions of third-party co-owners of interests in properties in which we also own an interest; and |
| ● | other risks and uncertainties described in “Item 1A. Risk Factors.” |
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 “Part I—Item 1A. Risk Factors” of Amplify’s Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on March 9, 2022 (“2021 Form 10-K”). All forward-looking statements speak only as of the date of this report. The Company does 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 the Company or persons acting on its behalf.
7
PART I—FINANCIAL INFORMATION
ITEM 1.FINANCIAL STATEMENTS.
AMPLIFY ENERGY CORP.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except outstanding shares)
| June 30, |
| December 31, | |||
| 2022 | 2021 | ||||
ASSETS |
|
|
|
| ||
Current assets: |
|
|
|
| ||
Cash and cash equivalents | $ | | $ | | ||
Accounts receivable, net (see Note 12) |
| |
| | ||
Short-term derivative instruments |
| |
| | ||
Prepaid expenses and other current assets |
| |
| | ||
Total current assets |
| |
| | ||
Property and equipment, at cost: |
|
|
|
| ||
Oil and natural gas properties, successful efforts method |
| |
| | ||
Support equipment and facilities |
| |
| | ||
Other |
| |
| | ||
Accumulated depreciation, depletion and amortization |
| ( |
| ( | ||
Property and equipment, net |
| |
| | ||
Restricted investments |
| |
| | ||
Operating lease - long term right-of-use asset |
| |
| | ||
Other long-term assets |
| |
| | ||
Total assets | $ | | $ | | ||
LIABILITIES AND EQUITY |
|
|
|
| ||
Current liabilities: |
|
|
|
| ||
Accounts payable | $ | | $ | | ||
Revenues payable |
| |
| | ||
Accrued liabilities (see Note 12) |
| |
| | ||
Short-term derivative instruments |
| |
| | ||
Total current liabilities |
| |
| | ||
Long-term debt (see Note 7) |
| |
| | ||
Asset retirement obligations |
| |
| | ||
Long-term derivative instruments |
| |
| | ||
Operating lease liability |
| |
| | ||
Other long-term liabilities |
| |
| | ||
Total liabilities |
| |
| | ||
Commitments and contingencies (see Note 14) |
|
|
|
| ||
Stockholders' equity (deficit): |
|
|
|
| ||
Preferred stock, $ |
|
| ||||
Warrants, |
| — |
| | ||
Common stock, $ |
| |
| | ||
Additional paid-in capital |
| |
| | ||
Accumulated deficit |
| ( |
| ( | ||
Total stockholders' deficit |
| ( |
| ( | ||
Total liabilities and equity | $ | | $ | | ||
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
8
AMPLIFY ENERGY CORP.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
| For the Three Months Ended | For the Six Months Ended | |||||||||||
| June 30, | June 30, | |||||||||||
| 2022 |
| 2021 | 2022 |
| 2021 | |||||||
Revenues: |
|
|
|
|
|
|
| ||||||
Oil and natural gas sales | $ | | $ | | $ | | $ | | |||||
Other revenues |
| |
| |
| |
| | |||||
Total revenues |
| |
| |
| |
| | |||||
Costs and expenses: |
|
|
|
|
|
|
|
| |||||
Lease operating expense |
| |
| |
| |
| | |||||
Gathering, processing and transportation |
| |
| |
| |
| | |||||
Taxes other than income |
| |
| |
| |
| | |||||
Depreciation, depletion and amortization |
| |
| |
| |
| | |||||
General and administrative expense |
| |
| |
| |
| | |||||
Accretion of asset retirement obligations |
| |
| |
| |
| | |||||
Loss (gain) on commodity derivative instruments |
| |
| |
| |
| | |||||
Pipeline incident loss | | | | | |||||||||
Other, net |
| |
| |
| |
| | |||||
Total costs and expenses |
| |
| |
| |
| | |||||
Operating income (loss) |
| |
| ( |
| ( |
| ( | |||||
Other income (expense) income: |
|
|
|
|
|
|
|
| |||||
Interest expense, net |
| ( |
| ( |
| ( |
| ( | |||||
Gain on extinguishment of debt |
| — |
| |
| — |
| | |||||
Other income (expense) | | ( | | ( | |||||||||
Total other income (expense) |
| ( |
| |
| ( |
| ( | |||||
Income (loss) before reorganization items, net and income taxes |
| |
| ( |
| ( |
| ( | |||||
Reorganization items, net |
| |
| |
| |
| ( | |||||
Income tax expense |
| |
| |
| |
| | |||||
Net income (loss) | $ | | $ | ( | $ | ( | $ | ( | |||||
Allocation of net income (loss) to: | |||||||||||||
Net income (loss) available to common stockholders | $ | | $ | ( | $ | ( | $ | ( | |||||
Net income (loss) allocated to participating securities |
| |
| — |
| — |
| — | |||||
Net income (loss) available to Amplify Energy Corp. | $ | | $ | ( | $ | ( | $ | ( | |||||
Earnings (loss) per share: (See Note 9) |
|
|
|
|
|
|
|
| |||||
Basic and diluted earnings (loss) per share | | ( | ( | ( | |||||||||
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
| |||||
Basic and diluted |
| |
| |
| |
| | |||||
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
9
AMPLIFY ENERGY CORP.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| For the Six Months Ended | |||||
| June 30, | |||||
| 2022 |
| 2021 | |||
Cash flows from operating activities: |
|
|
|
| ||
Net income (loss) | $ | ( | $ | ( | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
| ||
Depreciation, depletion and amortization |
| |
| | ||
Loss (gain) on derivative instruments |
| |
| | ||
Cash settlements (paid) received on expired derivative instruments |
| ( |
| ( | ||
Bad debt expense |
| |
| | ||
Amortization and write-off of deferred financing costs |
| |
| | ||
Gain on extinguishment of debt | — | ( | ||||
Accretion of asset retirement obligations |
| |
| | ||
Share-based compensation (see Note 10) |
| |
| | ||
Settlement of asset retirement obligations |
| ( |
| ( | ||
Changes in operating assets and liabilities: |
|
|
|
| ||
Accounts receivable |
| ( |
| ( | ||
Prepaid expenses and other assets |
| ( |
| | ||
Payables and accrued liabilities |
| |
| | ||
Other |
| ( |
| ( | ||
Net cash provided by operating activities |
| |
| | ||
Cash flows from investing activities: |
|
|
|
| ||
Additions to oil and gas properties |
| ( |
| ( | ||
Additions to other property and equipment |
| — |
| ( | ||
Additions to restricted investments |
| ( |
| | ||
Other |
| — |
| | ||
Net cash used in investing activities |
| ( |
| ( | ||
Cash flows from financing activities: |
|
|
|
| ||
Advances on revolving credit facility |
| |
| — | ||
Payments on revolving credit facility |
| ( |
| ( | ||
Deferred financing costs |
| ( |
| ( | ||
Shares withheld for taxes |
| ( |
| ( | ||
Other |
| |
| | ||
Net cash used in financing activities |
| ( |
| ( | ||
Net change in cash and cash equivalents |
| ( |
| | ||
Cash and cash equivalents, beginning of period |
| |
| | ||
Cash and cash equivalents, end of period | $ | | $ | | ||
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
10
AMPLIFY ENERGY CORP.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (DEFICIT)
(In thousands)
| Stockholders' Equity (Deficit) |
| ||||||||||||||
| Additional |
|
| |||||||||||||
Common | Paid-in | Accumulated | ||||||||||||||
| Stock |
| Warrants |
| Capital |
| Deficit |
| Total |
| ||||||
Balance at December 31, 2021 |
| $ | | $ | | $ | | $ | ( | $ | ( | |||||
Net income (loss) |
| |
|
|
| ( |
| ( | ||||||||
Share-based compensation expense |
| |
|
| |
|
| | ||||||||
Shares withheld for taxes |
| |
|
| ( |
|
| ( | ||||||||
Other |
| |
|
| ( |
|
| |
| |||||||
Balance at March 31, 2022 | | | | ( | ( | |||||||||||
Net income (loss) | | | | | | |||||||||||
Share-based compensation expense | | | | | | |||||||||||
Shares withheld for taxes | | | ( | | ( | |||||||||||
Expiration of warrants | | ( | | | | |||||||||||
Other | | | ( | | | |||||||||||
Balance at June 30, 2022 | $ | | $ | | $ | | $ | ( | $ | ( | ||||||
Stockholders' Equity (Deficit) | |||||||||||||||
Additional | Accumulated |
| |||||||||||||
Common | Paid-in | Earnings | |||||||||||||
| Stock |
| Warrants |
| Capital |
| (Deficit) |
| Total | ||||||
Balance at December 31, 2020 |
| $ | |
| $ | |
| $ | |
| $ | ( |
| $ | ( |
Net income (loss) |
|
|
|
| ( |
| ( | ||||||||
Share-based compensation expense |
|
|
| ( |
|
| ( | ||||||||
Shares withheld for taxes |
|
|
| ( |
|
| ( | ||||||||
Other |
| |
|
| ( |
| |
| | ||||||
Balance at March 31, 2021 |
| |
| |
| |
| ( |
| ( | |||||
Net income (loss) |
|
|
| ( |
| ( | |||||||||
Share-based compensation expense |
|
| |
|
| | |||||||||
Shares withheld for taxes |
|
| ( |
|
| ( | |||||||||
Balance at June 30, 2021 | $ | | $ | | $ | | $ | ( | $ | ( | |||||
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
11
Note 1. Organization and Basis of Presentation
General
Amplify Energy Corp. (“Amplify Energy,” “it” or the “Company”) is a publicly traded Delaware corporation whose common stock is listed on the NYSE under the symbol “AMPY.”
The Company is engaged in the acquisition, development, exploitation and production of oil and natural gas properties located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas/North Louisiana and the Eagle Ford. 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.
Basis of Presentation
The Company’s accompanying Unaudited Condensed Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the Company’s opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments of a normal recurring nature necessary for fair presentation. Material intercompany transactions and balances have been eliminated.
The results reported in these Unaudited Condensed Consolidated Financial Statements are not necessarily indicative of results that may be expected for the entire year. Furthermore, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. Accordingly, the accompanying Unaudited Condensed Consolidated Financial Statements and Notes should be read in conjunction with the Company’s annual financial statements included in its 2021 Form 10-K.
Use of Estimates
The preparation of the accompanying Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Significant estimates include, but are not limited to, oil and natural gas reserves; fair value estimates; revenue recognition; and contingencies and insurance accounting.
Market Conditions and COVID-19
Since the start of the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil and to a lesser extent natural gas and NGLs. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs and related commodity pricing, has improved.
12
Additionally, oil, natural gas and NGLs prices increased in the first half of 2022 when compared to the same period of 2021 and, as a result, the Company experienced a significant increase in revenues. The Company continues to monitor the impact of the actions of the Organization of the Petroleum Exporting Countries and other large producing nations, the Russia-Ukraine conflict, global inventories of oil and gas and the uncertainty associated with recovering oil demand, future monetary policy and governmental policies aimed at transitioning towards lower carbon energy. The Company expects prices for some or all of the commodities to remain volatile. Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions or other medical advances to combat the virus may impact the recovery of world economic growth and the demand for oil, natural gas and NGLs.
Note 2. Summary of Significant Accounting Policies
There have been no changes to the Company’s significant accounting policies as described in the Company’s annual financial statements included in its 2021 Form 10-K.
New Accounting Pronouncements
The Company has implemented all new accounting pronouncements that are in effect. These pronouncements did not have any material impact on the financial statements unless otherwise disclosed, and the Company does not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on its financial position or results of operations.
Note 3. Revenue
Revenue from Contracts with Customers
Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the reporting organization satisfies a performance obligation.
The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as gathering, processing and transportation, and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered.
Disaggregation of Revenue
The Company has identified
| For the Three Months Ended | For the Six Months Ended | |||||||||||
| June 30, | June 30, | |||||||||||
| 2022 |
| 2021 |
| 2022 |
| 2021 | ||||||
| (in thousands) | ||||||||||||
Revenues |
|
|
|
|
|
|
| ||||||
Oil | $ | | $ | | $ | | $ | | |||||
NGLs | | | | | |||||||||
Natural gas | | | | | |||||||||
Oil and natural gas sales | $ | | $ | | $ | | $ | | |||||
13
Contract Balances
Under the Company’s sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers was $
Note 4. Fair Value Measurements of Financial Instruments
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All the derivative instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets were considered Level 2.
The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying Unaudited Condensed Consolidated Balance Sheets approximated fair value at June 30, 2022 and December 31, 2021. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The fair market values of the derivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2022 and December 31, 2021 were based on estimated forward commodity prices. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following tables present the gross derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2022 and December 31, 2021 for each of the fair value hierarchy levels:
| Fair Value Measurements at June 30, 2022 | |||||||||||
Significant | ||||||||||||
Quoted Prices in | Significant Other | Unobservable | ||||||||||
Active Market | Observable Inputs | Inputs | ||||||||||
| (Level 1) |
| (Level 2) |
| (Level 3) |
| Fair Value | |||||
(In thousands) | ||||||||||||
Assets: |
|
|
|
|
|
|
|
| ||||
Commodity derivatives | $ | | $ | | $ | | $ | | ||||
Interest rate derivatives |
| |
| |
| |
| | ||||
Total assets | $ | | $ | | $ | | $ | | ||||
Liabilities: |
|
|
|
|
|
|
|
| ||||
Commodity derivatives | $ | | $ | | $ | | $ | | ||||
Interest rate derivatives |
| |
| |
| |
| | ||||
Total liabilities | $ | | $ | | $ | | $ | | ||||
14
| Fair Value Measurements at December 31, 2021 | |||||||||||
Significant | ||||||||||||
Quoted Prices in | Significant Other | Unobservable | ||||||||||
Active Market | Observable Inputs | Inputs | ||||||||||
| (Level 1) |
| (Level 2) |
| (Level 3) |
| Fair Value | |||||
(In thousands) | ||||||||||||
Assets: |
|
|
|
| ||||||||
Commodity derivatives | $ | | $ | | $ | | $ | | ||||
Interest rate derivatives |
| |
| |
| |
| | ||||
Total assets | $ | | $ | | $ | | $ | | ||||
Liabilities: |
|
|
|
|
|
|
|
| ||||
Commodity derivatives | $ | | $ | | $ | | $ | | ||||
Interest rate derivatives |
| |
| |
| |
| | ||||
Total liabilities | $ | | $ | | $ | | $ | | ||||
See Note 5 for additional information regarding the Company’s derivative instruments.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis, as reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets. The following methods and assumptions are used to estimate the fair values:
| ● | The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. The initial fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See Note 6 for a summary of changes in AROs. |
| ● | Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The Company uses an income approach based on the discounted cash flow method, whereby the present value of expected future net cash flows is discounted by applying an appropriate discount rate, for purposes of placing a fair value on the assets. The future cash flows are based on management’s estimates for the future. The unobservable inputs used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties (some of which are Level 3 inputs within the fair value hierarchy). |
| ● |
Note 5. Risk Management and Derivative Instruments
Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and to achieve a more predictable cash flow in connection with natural gas and oil sales and borrowing related activities. These instruments limit exposure to declines in prices but also limit the benefits that would be realized if prices increase.
15
Certain inherent business risks are associated with commodity derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is the Company’s 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 the Company’s current credit agreements are counterparties to its derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. The Company has also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of its counterparties. The terms of the ISDA Agreements provide the Company and each of its counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or its counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. See Note 7 for additional information regarding the Company’s Revolving Credit Facility (as defined below).
Commodity Derivatives
The Company may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars and three-way collars) to manage exposure to commodity price volatility. The Company recognizes all derivative instruments at fair value.
The Company enters into natural gas derivative contracts that are indexed to NYMEX-Henry Hub. The Company also enters into oil derivative contracts indexed to NYMEX-WTI. The Company’s NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.
16
At June 30, 2022, the Company had the following open commodity positions:
2022 |
| 2023 | ||||
Natural Gas Derivative Contracts: |
|
|
| |||
Fixed price swap contracts: |
|
|
| |||
Average monthly volume (MMBtu) | |
| ||||
Weighted-average fixed price | $ | | $ | |||
|
| |||||
Collar contracts: |
|
|
|
| ||
Two-way collars |
|
|
|
| ||
Average monthly volume (MMBtu) |
| |
| | ||
Weighted-average floor price | $ | | $ | | ||
Weighted-average ceiling price | $ | | $ | | ||
|
| |||||
Crude Oil Derivative Contracts: |
|
|
|
| ||
Fixed price swap contracts: |
|
|
|
| ||
Average monthly volume (Bbls) |
| |
| | ||
Weighted-average fixed price | $ | | $ | | ||
Collar contracts: |
|
|
|
| ||
Two-way collars | ||||||
Average monthly volume (Bbls) | | |||||
Weighted-average floor price | $ | | $ | |||
Weighted-average ceiling price | $ | | $ | |||
|
| |||||
Three-way collars |
|
|
|
| ||
Average monthly volume (Bbls) |
| |
| | ||
Weighted-average ceiling price | $ | | $ | | ||
Weighted-average floor price | $ | | $ | | ||
Weighted-average sub-floor price | $ | | $ | | ||
Interest Rate Swaps
Periodically, the Company enters into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in its Revolving Credit Facility to fixed interest rates.
| Remaining | |||
2022 |
| |||
Average Monthly Notional (in thousands) | $ | | ||
Weighted-average fixed rate |
| | % | |
Floating rate |
| |||
Balance Sheet Presentation
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2022 and December 31, 2021. There was no cash collateral received or pledged associated with the Company’s derivative instruments since most of its counterparties, or certain of its affiliates, to its derivative contracts are lenders under its Revolving Credit Facility.
17
|
| Asset |
| Liability |
| Asset |
| Liability | ||||||
Derivatives | Derivatives | Derivatives | Derivatives | |||||||||||
June 30, | June 30, | December 31, | December 31, | |||||||||||
Type |
| Balance Sheet Location |
| 2022 |
| 2022 |
| 2021 |
| 2021 | ||||
(In thousands) | ||||||||||||||
Commodity contracts |
| Short-term derivative instruments | $ | | $ | | $ | | $ | | ||||
Interest rate swaps |
| Short-term derivative instruments |
| |
| |
| |
| | ||||
Gross fair value |
|
| |
| |
| |
| | |||||
Netting arrangements |
|
| ( |
| ( |
| ( |
| ( | |||||
Net recorded fair value |
| Short-term derivative instruments | $ | | $ | | $ | | $ | | ||||
Commodity contracts |
| Long-term derivative instruments | $ | | $ | | $ | | $ | | ||||
Interest rate swaps |
| Long-term derivative instruments |
| |
| |
| |
| | ||||
Gross fair value |
|
| |
| |
| |
| | |||||
Netting arrangements |
|
| ( |
| ( |
| ( |
| ( | |||||
Net recorded fair value |
| Long-term derivative instruments | $ | | $ | | $ | | $ | | ||||
Loss (Gain) on Derivative Instruments
The Company does not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying Unaudited Condensed Consolidated Statements of Operations.
|
| For the Three Months Ended | For the Six Months Ended | ||||||||||||
Statements of |
| June 30, |
| June 30, | |||||||||||
| Operations Location | 2022 |
| 2021 | 2022 |
| 2021 | ||||||||
Commodity derivative contracts |
| Loss (gain) on commodity derivatives | $ | | $ | | $ | | $ | | |||||
(Gain) loss on interest rate derivatives |
| Interest expense, net |
| ( |
| |
| ( |
| ( | |||||
Note 6. Asset Retirement Obligations
The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2022 (in thousands):
Asset retirement obligations at beginning of period | $ | ||
Liabilities added from acquisition or drilling |
| | |
Liabilities settled |
| ( | |
Liabilities removed upon sale of wells |
| — | |
Accretion expense |
| | |
Revision of estimates |
| | |
Asset retirement obligation at end of period |
| | |
Less: Current portion |
| | |
Asset retirement obligations - long-term portion | $ | |
18
Note 7. Long-Term Debt
The following table presents the Company’s consolidated debt obligations at the dates indicated:
| June 30, | December 31, | ||||
2022 | 2021 | |||||
(In thousands) | ||||||
Revolving Credit Facility (1) | $ | | $ | | ||
Total long-term debt | $ | | $ | | ||
| (1) |
Revolving Credit Facility
OLLC, the Company’s wholly owned subsidiary, is a party to a reserve-based revolving credit facility (the “Revolving Credit Facility”), subject to a borrowing base of $
As of June 30, 2022, the Company was in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with its Revolving Credit Facility.
On June 20, 2022, OLLC entered into the Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement, among OLLC, Amplify Acquisitionco LLC, a Delaware limited liability company, the guarantors party thereto, the lenders party thereto and KeyBank National Association, as administrative agent (the “Sixth Amendment”). The Sixth Amendment amends the Revolving Credit Facility to, among other things:
| ● | terminate the automatic monthly reductions of the borrowing base; |
| ● | reaffirm the borrowing base under the Revolving Credit Facility at $ |
| ● | modify the affirmative hedging covenant. |
The Fall 2021 semi-annual borrowing base redetermination in November 2021, resulted in (1) the reaffirmation of the $
Weighted-Average Interest Rates
The following table presents the weighted-average interest rates paid, excluding commitment fees, on the Company’s consolidated variable-rate debt obligations for the periods presented:
For the Three Months Ended | For the Six Months Ended |
| ||||||||
June 30, | June 30, |
| ||||||||
2022 | 2021 | 2022 | 2021 |
| ||||||
Revolving Credit Facility | | % | | % | | % | | % | ||
Letters of Credit
At June 30, 2022, the Company had
19
Unamortized Deferred Financing Costs
Unamortized deferred financing costs associated with the Company’s Revolving Credit Facility was $
Paycheck Protection Program
On April 24, 2020, the Company received a $
Note 8. Equity (Deficit)
Common Stock
The Company’s authorized capital stock includes
| Common Stock | |
Balance, December 31, 2021 |
| |
Issuance of common stock |
| — |
Restricted stock units vested |
| |
Shares withheld for taxes (1) | ( | |
Balance, June 30, 2022 |
| |
| (1) |
Warrants
On May 4, 2017, Legacy Amplify entered into a warrant agreement with American Stock Transfer Trust Company, LLC, as warrant agent, pursuant to which Legacy Amplify issued warrants to purchase up to
20
Note 9. Earnings per Share
The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts):
| For the Three Months Ended | For the Six Months Ended | |||||||||||
June 30, | June 30, | ||||||||||||
2022 | 2021 | 2022 | 2021 | ||||||||||
Net income (loss) | $ | | $ | ( | $ | ( | $ | ( | |||||
Less: Net income allocated to participating securities |
| |
| |
| |
| | |||||
Basic and diluted earnings available to common stockholders | $ | | $ | ( | $ | ( | $ | ( | |||||
Common shares: |
|
|
|
|
|
|
|
| |||||
Common shares outstanding — basic |
| |
| |
| |
| | |||||
Dilutive effect of potential common shares |
| |
| |
| |
| | |||||
Common shares outstanding — diluted |
| |
| |
| |
| | |||||
Net earnings (loss) per share: |
|
|
|
|
|
|
|
| |||||
Basic | $ | | $ | ( | $ | ( | $ | ( | |||||
Diluted | $ | | $ | ( | $ | ( | $ | ( | |||||
Antidilutive warrants (1) |
| — |
| |
| — |
| | |||||
| (1) |
Note 10. Long-Term Incentive Plans
In May 2021, the shareholders approved a new Equity Incentive Plan (“EIP”) in which the Legacy Amplify Management Incentive Plan (the “Legacy Amplify MIP”) and the Legacy Amplify 2017 Non-Employee Directors Compensation Plan (the “Legacy Amplify Non-Employee Directors Compensation Plan”) were replaced by the EIP and no further awards will be allowed to be granted under the Legacy Amplify MIP or the Legacy Amplify Non-Employee Directors Compensation Plan. As of June 30, 2022, an aggregate of
Restricted Stock Units
Restricted Stock Units with Service Vesting Condition
The restricted stock units with service vesting conditions (“TSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with the TSUs was $
21
The following table summarizes information regarding the TSUs granted under the EIP for the period presented:
|
| Weighted- | |||
Average Grant- | |||||
Number of | Date Fair Value | ||||
Units | per Unit (1) | ||||
TSUs outstanding at December 31, 2021 |
| | $ | | |
Granted (2) |
| | $ | | |
Forfeited |
| ( | $ | | |
Vested |
| ( | $ | | |
TSUs outstanding at June 30, 2022 |
| | $ | | |
| (1) | Determined by dividing the aggregate grant-date fair value of awards by the number of awards issued. |
| (2) |
Restricted Stock Units with Market and Service Vesting Conditions
The restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost related to the PSUs was less than $
The PSUs will vest based on the satisfaction of service and market vesting conditions, with market vesting based on the Company’s achievement of certain share price targets. The PSUs are subject to service-based vesting such that
In the event of a qualifying termination, subject to certain conditions, (i) all PSUs that have satisfied the market vesting conditions will fully service vest, upon such termination, and (ii) if the termination occurs between the second and third anniversaries of the grant date, then PSUs that have not market vested as of the termination will market vest to the extent that the share targets (in each case, reduced by $
A Monte Carlo simulation was used in order to determine the fair value of these awards at the grant date.
The following table summarizes information regarding the PSUs granted under the EIP for the period presented:
|
| Weighted- | |||
Average Grant- | |||||
Number of | Date Fair Value | ||||
Units | per Unit (1) | ||||
PSUs outstanding at December 31, 2021 |
| | $ | | |
Granted |
| | $ | | |
Forfeited |
| ( | $ | | |
Vested |
| | $ | | |
PSUs outstanding at June 30, 2022 |
| | $ | | |
| (1) |
22
Restricted Stock Units with Market Vesting Conditions
The restricted stock units with performance-based vesting conditions (“PRSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense.
The 2022 PRSUs were issued with a three year vesting period beginning on the grant date and ending on the third anniversary of the grant date. Vesting of PRSUs can range from
The 2021 PRSUs awards were issued collectively in separate tranches with individual performances periods beginning in January 2021, 2022, and 2023 respectively. For each of the 2021 PRSUs awards the performance period, will vest based on the percentage of the target PRSUs subject to the performance vesting condition, with
The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2022 are presented as follows:
2022 |
| ||
Expected volatility |
| % | |
Dividend yield |
| % | |
Risk-free interest rate |
| % |
The following table summarizes information regarding the PRSUs granted under the EIP for the period presented:
|
| Weighted- | |||
Average Grant- | |||||
Number of | Date Fair Value | ||||
Units | per Unit (1) | ||||
PRSUs outstanding at December 31, 2021 |
| | $ | | |
Granted (2) |
| | $ | | |
Forfeited |
| | $ | | |
Vested |
| ( | $ | | |
PRSUs outstanding at June 30, 2022 |
| | $ | | |
| (1) | Determined by dividing the aggregate grant-date fair value of awards by the number of awards issued. |
| (2) |
2017 Non-Employee Directors Compensation Plan
In June 2017, Legacy Amplify implemented the Legacy Amplify Non-Employee Directors Compensation Plan to attract and retain the services of experienced non-employee directors of Legacy Amplify or its subsidiaries. In connection with the closing of the merger, on August 6, 2019, the Company assumed the Legacy Amplify Non-Employee Directors Compensation Plan. As noted above, the Legacy Amplify Non-Employee Directors Compensation Plan was replaced by the EIP in May 2021.
23
The restricted stock units with a service vesting condition (“Board RSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense.
|
| Weighted- | |||
Average Grant- | |||||
Number of | Date Fair Value | ||||
Units | per Unit (1) | ||||
Board RSUs outstanding at December 31, 2021 |
| | $ | | |
Granted |
| — | $ | — | |
Forfeited |
| — | $ | — | |
Vested |
| ( | $ | | |
Board RSUs outstanding at June 30, 2022 |
| — | $ | — | |
| (1) | Determined by dividing the aggregate grant-date fair value of awards by the number of awards issued. |
Compensation Expense
The following table summarizes the amount of recognized compensation expense associated with the EIP, which are reflected in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods presented (in thousands):
| For the Three Months Ended |
| For the Six Months Ended |
| |||||||||
June 30, | June 30, | ||||||||||||
2022 | 2021 | 2022 | 2021 | ||||||||||
Equity classified awards |
|
|
|
| |||||||||
TSUs | | | | | |||||||||
PSUs and PRSUs |
| |
| |
| |
| | |||||
Board RSUs |
| |
| |
| |
| | |||||
$ | | $ | | $ | | $ | | ||||||
Note 11. Leases
The Company has leases for office space and equipment in its corporate office and operating regions as well as warehouse space, vehicles, compressors and surface rentals related to its business operations. In addition, the Company has offshore Southern California pipeline right-of-way use agreements. Most of the Company’s leases, other than its corporate office lease, have an initial term and may be extended on a month-to-month basis after expiration of the initial term. Most of the Company’s
The Company’s corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, the Company uses its incremental borrowing rate based on the information available at the inception date. To determine the incremental borrowing rate, the Company applies a portfolio approach based on the applicable lease terms and the current economic environment. The Company uses a reasonable market interest rate for its office equipment and vehicle leases.
For the six months ended June 30, 2022 and 2021, the Company recognized approximately $
24
Supplemental cash flow information related to the Company’s lease liabilities is included in the table below:
| For the Six Months Ended |
| |||||
| June 30, |
| |||||
| 2022 |
| 2021 |
| |||
| (In thousands) |
| |||||
Non-cash amounts included in the measurement of lease liabilities: |
|
|
|
|
|
| |
Operating cash flows from operating leases |
| $ | |
| $ | |
|
The following table presents the Company’s right-of-use assets and lease liabilities for the period presented:
| June 30, | December 31, | ||||
2022 | 2021 | |||||
(In thousands) | ||||||
Right-of-use asset | $ | | $ | | ||
Lease liabilities: |
|
|
|
| ||
Current lease liability |
| 583 |
| | ||
Long-term lease liability |
| |
| | ||
Total lease liability | $ | | $ | | ||
The following table reflects the Company’s maturity analysis of the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):
Office and | Leased vehicles | ||||||||
warehouse | and office | ||||||||
| leases |
| equipment |
| Total | ||||
Remaining 2022 | $ | | $ | | $ | | |||
2023 | | | | ||||||
2024 | | | | ||||||
2025 | | | | ||||||
2026 and thereafter |
| |
| |
| | |||
Total lease payments |
| |
| |
| | |||
Less: interest |
| |
| |
| | |||
Present value of lease liabilities | $ | | $ | | $ | | |||
The weighted average remaining lease terms and discount rate for all of the Company’s operating leases for the period presented:
| June 30, |
| |||
2022 | 2021 |
| |||
Weighted average remaining lease term (years): |
|
|
| ||
Office and warehouse space |
|
| |||
Vehicles |
|
| |||
Office equipment |
|
| |||
Weighted average discount rate: |
|
|
|
| |
Office leases |
| | % | | % |
Vehicles |
| | % | | % |
Office equipment |
| | % | | % |
25
Note 12. Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Consolidated Statements of Cash Flows
Accrued Liabilities
Current accrued liabilities consisted of the following at the dates indicated (in thousands):
| June 30, | December 31, | ||||
2022 | 2021 | |||||
Accrued liability - pipeline incident | $ | | $ | | ||
Accrued lease operating expense | | | ||||
Accrued capital expenditures | | | ||||
Accrued production and ad valorem tax |
| |
| | ||
Accrued commitment fee and other expense |
| |
| | ||
Accrued general and administrative expense |
| |
| | ||
Asset retirement obligations |
| |
| | ||
| | |||||
Other |
| |
| — | ||
Accrued liabilities | $ | | $ | | ||
Accounts Receivable
Accounts receivable consisted of the following at the dates indicated (in thousands):
| June 30, | December 31, | ||||
2022 | 2021 | |||||
Oil and natural gas receivables | $ | | $ | | ||
Insurance receivable - pipeline incident | | | ||||
Joint interest owners and other | | | ||||
Total accounts receivable |
| |
| | ||
Less: allowance for doubtful accounts |
| ( |
| ( | ||
Total accounts receivable, net | $ | | $ | | ||
Supplemental Cash Flows
Supplemental cash flows for the periods presented (in thousands):
| For the Six Months Ended | |||||
June 30, | ||||||
2022 | 2021 | |||||
Supplemental cash flows: |
|
| ||||
Cash paid for interest, net of amounts capitalized | $ | | $ | | ||
Cash paid for reorganization items, net |
|
| |
| | |
Cash paid for taxes |
|
| |
| — | |
|
| |||||
Noncash investing and financing activities: |
|
|
|
|
| |
Increase (decrease) in capital expenditures in payables and accrued liabilities |
|
| |
| | |
26
Note 13. Related Party Transactions
Related Party Agreements
There have been
Note 14. Commitments and Contingencies
Litigation and Environmental
As of June 30, 2022, the Company had no material contingent liabilities recorded in its Unaudited Condensed Consolidated Financial Statements associated with any litigation, pending or threatened.
Although the Company is insured against various risks to the extent it believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify it against liabilities arising from future legal proceedings.
At June 30, 2022 and December 31, 2021, the Company had
Southern California Pipeline Incident
The Company and certain of its subsidiaries are named defendants in a putative class action pending in the United States District Court for the Central District of California. The plaintiffs seek unspecified monetary damages and certain forms of injunctive relief. The Company is also participating in a related claims process organized under the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq. (“OPA 90”). Under OPA 90, a party alleged to be responsible for a discharge of oil is required to establish a claims process to pay for interim costs and damages as a result of the discharge. The OPA 90 claims process remains ongoing.
Future litigation may be necessary, among other things, to defend the Company by determining the scope, enforceability, and validity of claims. The results of any current or future litigation cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on the Company because of defense and settlement costs, diversion of management resources, and other factors.
Minimum Volume Commitment
The Company is party to a gas purchase, gathering and processing contract in Oklahoma, which includes certain minimum NGL commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The Company is not meeting the minimum volume required under this contractual provision. The commitment fee expense for the three and six months ended June 30, 2022 was approximately $
The Company is party to a gas purchase, gathering and processing contract in East Texas, which includes certain minimum gas commitments. The Company is not meeting the minimum volume required under this contractual provision. The commitment fee expense for the three and six months ended June 30, 2022, was approximately $
27
Sinking Fund Trust Agreement
Beta Operating Company, LLC, a wholly owned subsidiary, assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Company properties in federal waters offshore Southern California, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay Pipeline that lies within state waters and the surface facilities. Under the terms of the agreement, the operator of the properties is obligated to make monthly deposits into the sinking fund account in an amount equal to $
Supplemental Bond for Decommissioning Liabilities Trust Agreement
Beta Operating Company, LLC (“Beta”), a wholly owned subsidiary of the Company, has an obligation with the BOEM in connection with its 2009 acquisition of the Company’s properties in federal waters offshore Southern California. The Company supports this obligation with $
Note 15. Income Taxes
The Company had
Note 16. Southern California Pipeline Incident
On October 2, 2021, contractors operating under the direction of Beta, a subsidiary of Amplify, observed an oil sheen on the water approximately
On October 5, 2021, the Unified Command announced that reports from its contracted commercial divers and Remotely Operated Vehicle footage indicated that a
28
At the height of the Incident response, the Company deployed over
In response to the Incident, all operations have been suspended and the pipeline has been shut-in until the Company receives the required regulatory approvals to begin operations. On October 4, 2021, the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) issued a Corrective Action Order (CAO) pursuant to 49 U.S.C. § 60112, which makes clear that no restart of the affected pipeline may occur until PHMSA has approved a written restart plan. Additionally, the California Coastal Commission requested approval from the Office of Coastal Management for the National Oceanic and Atmospheric Association (NOAA) to conduct a Coastal Zone Management Act consistency review of the U.S. Army Corps of Engineers Nationwide Permit (NWP) 12 application for the proposed permanent repair permit; on April 7, 2022, NOAA denied that request. The Company is working expeditiously and cooperatively to comply with the requirements of the relevant agencies in order to gain such approvals and any other regulatory approvals that are necessary to permanently repair the pipeline and restart operations. As a result of the uncertainties related to the permitting and regulatory approval process, the Company can provide no assurances as to whether and when, if at all, operation will restart at the Beta field. At present, no operations are underway in the Beta field.
On December 15, 2021, a federal grand jury in the Central District of California returned a federal criminal indictment against Amplify Energy Corp., Beta Operating Company, LLC, and San Pedro Bay Pipeline Company in connection with the Incident. The indictment alleges that the Company committed a misdemeanor violation of the federal Clean Water Act for negligently discharging oil into the contiguous zone of the United States. A trial is set for November 1, 2022. The United States Attorney’s Office for the Central District of California has stated that its investigation of the Incident and related matters is ongoing. State authorities are conducting parallel criminal investigations as well. We are continuing to cooperate with these federal and state investigations. The outcome of these investigations is uncertain, including whether they will result in additional criminal charges.
The Company is currently subject to a number of ongoing investigations related to the Incident by certain federal and state agencies. To date, the U.S. Coast Guard, the U.S. Bureau of Ocean Energy Management, the U.S. Department of Justice, PHMSA, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement, the California Department of Justice, the Orange County District Attorney, the Los Angeles County District Attorney, and the California Department of Fish Wildlife are conducting investigations or examinations of the Incident. On April 8, 2022, in light of the allegations raised in the December 15, 2021 federal indictment, the Company received a Show Cause Notice from the U.S. Environmental Protection Agency (“EPA”) asking the Company to provide information as to why it should not be suspended from participating in future Federal contracting and assisting activities pursuant to 2 C.F.R. § 180.700(a), (c) and 2 C.F.R. § 180.800(a)(4). On April 22, 2022, the Company responded to the Show Cause Notice and is working cooperatively with the EPA in connection with this matter. Other federal agencies may or have commenced investigations and proceedings, and may initiate enforcement actions seeking penalties and other relief under the Clean Water Act and other statutes. Amplify continues to comply with all regulatory requirements and investigations. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil and criminal liability.
29
The Company and
Under the OPA 90, the Company’s pipeline was designated by the U.S. Coast Guard as the source of the oil discharge and therefore the Company is financially responsible for remediation and for certain costs and economic damages as provided for in OPA 90, as well as certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages. The Company is currently processing covered claims under OPA 90 as expeditiously as possible. In addition, the Natural Resource Damage Assessment remains ongoing and therefore the extent, timing and cost related to such assessment are difficult to project. While the Company anticipates insurance will reimburse it for expenses related to the Natural Resource Damage Assessment, any potentially uncovered expenses may be material and could impact the Company’s business and results of operations and could put pressure on its liquidity position going forward.
The Company currently estimates that the total costs it has incurred or will incur with respect to the Incident to be approximately $
In accordance with customary insurance practice, the Company maintains insurance policies, including loss of production income insurance, against many potential losses or liabilities arising from its operations and at costs that the Company believes to be economic. The Company regularly reviews its risk of loss and the cost and availability of insurance and revises its insurance accordingly. The Company’s insurance does not cover every potential risk associated with its operations and is subject to certain exclusions and deductibles. While the Company expects its insurance policies will cover a material portion of the total aggregate costs associated with the Incident, including but not limited to response and remediation expenses, defense costs and loss of revenue resulting from suspended operations, it can provide no assurance that its coverage will adequately protect it against liability from all potential consequences, damages and losses related to the Incident and such view and understanding is preliminary and subject to change.
30
For the six months ended June 30, 2022, the Company incurred total aggregate gross costs of $
On June 30, 2022, and December 31, 2021, the Company’s insurance receivables were $
Additionally, during the six months ended June 30, 2022, the Company recognized $
Subsequent to June 30, 2022, the Company received approval for approximately $
31
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Unaudited Condensed Consolidated Financial Statements and accompanying notes in “Item 1. Financial Statements” contained herein and in “Item 1A. Risk Factors” of our Annual Report on the Form 10-K for the year ended December 31, 2021 (“2021 Form 10-K”). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.
Overview
We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on the reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas / North Louisiana and the Eagle Ford. Our properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.
Industry Trends
Since the start of the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil and to a lesser extent natural gas and NGLs. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs and related commodity pricing, has improved.
Additionally, oil, natural gas and NGLs prices increased in the first half of 2022 when compared to the same period of 2021 and, as a result, we experienced a significant increase in revenues. We continue to monitor the impact of the actions of the Organization of the Petroleum Exporting Countries and other large producing nations, the Russia-Ukraine conflict, global inventories of oil and gas and the uncertainty associated with recovering oil demand, future monetary policy and governmental policies aimed at transitioning towards lower carbon energy. We expect prices for some or all of the commodities to remain volatile. Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions or other medical advances to combat the virus may impact the recovery of world economic growth and the demand for oil, natural gas and NGLs.
Recent Developments
Borrowing Base Redetermination and Sixth Amendment
On June 21, 2022, OLLC entered into the Sixth Amendment. The Sixth Amendment amends the Revolving Credit Facility to, among other things:
| ● | terminate the automatic monthly reductions of the borrowing base; |
| ● | reaffirm the borrowing base under the Revolving Credit Facility at $225.0 million; and |
| ● | modify the affirmative hedging covenant. |
Special Case Royalty Relief
On June 8, 2022, the Special Case Royalty Relief for our interest in the Beta Unit was terminated.
32
Appointment of Certain Directors
On April 7, 2022, the board of directors of the Company appointed Deborah G. Adams and Eric T. Greager to the board of directors, effective April 7, 2022. Ms. Adams has also been appointed to the nominating and governance committee of the board of directors, and Mr. Greager has also been appointed to the compensation committee of the board of directors.
Business Environment and Operational Focus
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production; (iii) cash settlements on our commodity derivatives; (iv) lease operating expense; (v) gathering, processing and transportation; (vi) general and administrative expense; and (vii) Adjusted EBITDA (as defined below).
Sources of Revenues
Our revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. Natural gas, NGL and oil prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in natural gas and oil prices on revenues, we intend to periodically enter into derivative contracts that fix the future prices received. At the end of each period, the fair value of these commodity derivative instruments is estimated and because hedge accounting is not elected, the changes in the fair value of unsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates, including a discussion regarding the estimation uncertainty and the impact that our critical accounting estimates have had, or are reasonably likely to have, on our financial condition or results of operations, are described in Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2021 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; fair value estimates; revenue recognition; and contingencies and insurance accounting. These estimates, in our opinion, are subjective in nature, require the use of professional judgment and involve complex analysis.
When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.
33
Results of Operations
The results of operations for the three and six months ended June 30, 2022 and 2021 have been derived from our unaudited condensed consolidated financial statements. The comparability of the results of operations among the periods presented below is impacted by the Incident and suspension of operations at our Beta properties.
The following table summarizes certain of the results of operations for the periods indicated.
| For the Three Months Ended | For the Six Months Ended | |||||||||||
| June 30, | June 30, | |||||||||||
| 2022 |
| 2021 | 2022 |
| 2021 | |||||||
| ($ In thousands except per unit amounts) | ||||||||||||
Oil and natural gas sales | $ | 112,878 | $ | 80,338 | $ | 206,750 | $ | 152,669 | |||||
Other revenues | 8,899 | 55 | 26,460 | 193 | |||||||||
Lease operating expense |
| 33,285 |
| 28,653 |
| 66,205 |
| 57,559 | |||||
Gathering, processing and transportation |
| 7,281 |
| 5,050 |
| 15,291 |
| 9,629 | |||||
Taxes other than income |
| 8,623 |
| 5,071 |
| 16,176 |
| 9,684 | |||||
Depreciation, depletion and amortization |
| 5,864 |
| 7,389 |
| 11,499 |
| 14,736 | |||||
General and administrative expense |
| 8,628 |
| 6,030 |
| 16,399 |
| 12,951 | |||||
Loss (gain) on commodity derivative instruments |
| 18,571 |
| 63,898 |
| 111,975 |
| 98,486 | |||||
Pipeline incident loss | 5,092 |
| — |
| 5,672 |
| — | ||||||
Interest expense, net |
| 3,084 |
| 3,137 |
| 5,525 |
| 6,249 | |||||
Gain on extinguishment of debt |
| — |
| 5,516 |
| — |
| 5,516 | |||||
Net income (loss) |
| 29,220 |
| (35,023) |
| (19,394) |
| (54,351) | |||||
Oil and natural gas revenues: |
|
|
|
|
|
|
|
| |||||
Oil sales | $ | 58,918 | $ | 56,510 | $ | 111,292 | $ | 106,205 | |||||
NGL sales |
| 13,604 |
| 8,876 |
| 27,085 |
| 16,547 | |||||
Natural gas sales |
| 40,356 |
| 14,952 |
| 68,373 |
| 29,917 | |||||
Total oil and natural gas revenues | $ | 112,878 | $ | 80,338 | $ | 206,750 | $ | 152,669 | |||||
Production volumes: |
|
|
|
|
|
|
|
| |||||
Oil (MBbls) |
| 557 |
| 905 |
| 1,137 |
| 1,824 | |||||
NGLs (MBbls) |
| 347 |
| 368 |
| 685 |
| 710 | |||||
Natural gas (MMcf) |
| 5,725 |
| 6,161 |
| 11,235 |
| 11,922 | |||||
Total (MBoe) |
| 1,858 |
| 2,300 |
| 3,695 |
| 4,521 | |||||
Average net production (MBoe/d) |
| 20.4 |
| 25.3 |
| 20.4 |
| 25.0 | |||||
Average realized sales price (excluding commodity derivatives): |
|
|
|
|
|
|
|
| |||||
Oil (per Bbl) | $ | 105.79 | $ | 62.47 | $ | 97.84 | $ | 58.21 | |||||
NGL (per Bbl) |
| 39.18 |
| 24.09 |
| 39.51 |
| 23.30 | |||||
Natural gas (per Mcf) |
| 7.05 |
| 2.43 |
| 6.09 |
| 2.51 | |||||
Total (per Boe) | $ | 60.74 | $ | 34.93 | $ | 55.95 | $ | 33.76 | |||||
Average unit costs per Boe: |
|
|
|
|
|
|
|
| |||||
Lease operating expense | $ | 17.91 | $ | 12.46 | $ | 17.92 | $ | 12.73 | |||||
Gathering, processing and transportation |
| 3.92 |
| 2.20 |
| 4.14 |
| 2.13 | |||||
Taxes other than income |
| 4.64 |
| 2.20 |
| 4.38 |
| 2.14 | |||||
General and administrative expense |
| 4.64 |
| 2.62 |
| 4.44 |
| 2.86 | |||||
Depletion, depreciation and amortization |
| 3.16 |
| 3.21 |
| 3.11 |
| 3.26 | |||||
34
For the Three Months Ended June 30, 2022 Compared to the Three Months Ended June 30, 2021
Net income of $29.2 million and a net loss of $35.0 million were recorded for the three months ended June 30, 2022 and 2021, respectively.
Oil, natural gas and NGL revenues were $112.9 million and $80.3 million for the three months ended June 30, 2022 and 2021, respectively. Average net production volumes were approximately 20.4 MBoe/d and 25.3 MBoe/d for the three months ended June 30, 2022 and 2021, respectively. The change in production volumes was primarily due to the suspension of operations at our Beta properties and natural declines. For the three months ended June 30, 2021, production from our Beta properties was 3.6 MBoe/d. The average realized sales price was $60.74 per Boe and $34.93 per Boe for the three months ended June 30, 2022 and 2021, respectively. The increase in average realized sales price was primarily due to the increase in commodity prices.
Other revenues were $8.9 million and less than $0.1 million for the three months ended June 30, 2022 and 2021, respectively. For the three months ended June 30, 2022, we recognized $8.8 million of LOPI proceeds related to the suspension of operations at our Beta properties resulting from the Incident which includes two months of LOPI.
Lease operating expense was $33.3 million and $28.7 million for the three months ended June 30, 2022 and 2021, respectively. The change in lease operating expense was primarily related to a $2.8 million increase in workover expense and an increase of $2.1 million in lease operating expenses, offset by the natural decline in production. The increase was primarily attributable to increased expense workover projects in Oklahoma and the Rockies. On a per Boe basis, lease operating expense was $17.91 and $12.46 for the three months ended June 30, 2022 and 2021, respectively. The change in lease operating expense on a per Boe basis was due mainly to higher costs and lower production.
Gathering, processing and transportation was $7.3 million and $5.1 million for the three months ended June 30, 2022 and 2021, respectively. The increase was primarily attributable to marketing our own natural gas in Oklahoma, resulting in a reclassification of certain revenue deductions to gathering, processing and transportation expenses. On a per Boe basis, gathering, processing and transportation was $3.92 and $2.20 for the three months ended June 30, 2022 and 2021, respectively. The change on a per BOE basis primarily related to higher commodity prices and the accounting reclassification discussed above.
Taxes other than income were $8.6 million and $5.1 million for the three months ended June 30, 2022 and 2021, respectively. The increase in taxes other than income is due to an increase in production taxes as a result of the increase in commodity prices. On a per Boe basis, taxes other than income were $4.64 and $2.20 for the three months ended June 30, 2022 and 2021, respectively. The change in taxes other than income on a per Boe basis was primarily due to the increase in commodity prices.
DDA expense was $5.9 million and $7.4 million for the three months ended June 30, 2022 and 2021, respectively. The change in DDA expense was primarily due to a decrease in production of 442 MBoe, which equates to a decrease of approximately $1.4 million.
General and administrative expense was $8.6 million and $6.0 million for the three months ended June 30, 2022 and 2021, respectively. The change in general and administrative expense was primarily related to (1) an increase of $1.4 million in salaries and other payroll benefits; (2) an increase of $0.6 million in legal expenses, and (3) an increase of $0.7 million in professional services.
Net loss on commodity derivative instruments of $18.6 million were recognized for the three months ended June 30, 2022, consisting of a $30.0 million increase in the fair value of open positions and $48.6 million of cash settlements paid on expired positions. Net loss on commodity derivative instruments of $63.9 million was recognized for the three months ended June 30, 2021, consisting of a $47.0 million decrease in the fair value of open positions and $16.9 million of cash settlements paid on expired positions.
Pipeline incident loss was $5.1 million for the three months ended June 30, 2022. The $5.1 million reflects legal expenses that the Company has determined will not be reimbursed through the insurance claims process. No expense was recorded for the three months ended June 30, 2021. See Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
35
Interest expense, net was $3.1 million and $3.1 million for the three months ended June 30, 2022 and 2021, respectively. Interest expense included a gain position on our interest rate swaps of $0.3 million for the three months ended June 30, 2022, compared to a loss position on interest rate swaps of less than $0.1 million for the three months ended June 30, 2021. In addition, we had an increase of $0.3 million in interest expense due to higher rates on our Revolving Credit Facility.
Average outstanding borrowings under our Revolving Credit Facility were $219.4 million and $242.8 million for the three months ended June 30, 2022 and 2021, respectively.
For the Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021
Net losses of $19.4 million and $54.4 million were recorded for the six months ended June 30, 2022 and 2021, respectively.
Oil, natural gas and NGL revenues were $206.8 million and $152.7 million for the six months ended June 30, 2022 and 2021, respectively. Average net production volumes were approximately 20.4 MBoe/d and 25.0 MBoe/d for the six months ended June 30, 2022 and 2021, respectively. The change in production volumes was primarily due to the suspension of operations at our Beta properties and natural declines. During the first half of 2021, production from our Beta properties was 3.6 MBoe/d. The average realized sales price was $55.95 per Boe and $33.76 per Boe for the six months ended June 30, 2022 and 2021, respectively. The increase in average realized sales price was primarily due to the increase in commodity prices.
Other revenues were $26.5 million and $0.2 million for the six months ended June 30, 2022 and 2021, respectively. During the first half of 2022, we recognized $26.2 million of LOPI proceeds related to the suspension of operations at our Beta properties resulting from the Incident which includes six months of LOPI.
Lease operating expense was $66.2 million and $57.6 million for the six months ended June 30, 2022 and 2021, respectively. The change in lease operating expense was primarily related to a $5.5 million increase in workover expense and $4.7 million increase in lease operating expense, offset by the natural decline in production. The increase was primarily attributable to increased expense workover projects in Oklahoma and the Rockies. On a per Boe basis, lease operating expense was $17.92 and $12.73 for the six months ended June 30, 2022 and 2021, respectively. The change in lease operating expense on a per Boe basis was due mainly to higher costs and lower production.
Gathering, processing and transportation was $15.3 million and $9.6 million for the six months ended June 30, 2022 and 2021, respectively. The increase was primarily attributable to marketing our own natural gas in Oklahoma, resulting in a reclassification of certain revenue deductions to gathering, processing and transportation expenses. On a per Boe basis, gathering, processing and transportation was $4.14 and $2.13 for the six months ended June 30, 2022 and 2021, respectively. The change on a per BOE basis primarily related to higher commodity prices and the accounting reclassification discussed above.
Taxes other than income were $16.2 million and $9.7 million for the six months ended June 30, 2022 and 2021, respectively. The increase in taxes other than income is due to an increase in production taxes as a result of the increase in commodity prices. On a per Boe basis, taxes other than income were $4.38 and $2.14 for the six months ended June 30, 2022 and 2021, respectively. The change in taxes other than income on a per Boe basis was primarily due to the increase in commodity prices.
DDA expense was $11.5 million and $14.7 million for the six months ended June 30, 2022 and 2021, respectively. The change in DDA expense was primarily due to a decrease in production of 826 MBoe, which equates to a decrease of approximately $2.7 million.
General and administrative expense was $16.4 million and $13.0 million for the six months ended June 30, 2022 and 2021, respectively. The change in general and administrative expense was primarily related to (1) an increase of $1.6 million in salaries and other payroll benefits, (2) an increase of $0.7 million in stock compensation expense, (3) an increase of $0.7 million in legal expenses, and (4) an increase of $0.4 million in professional services.
Net loss on commodity derivative instruments of $112.0 million were recognized for the six months ended June 30, 2022, consisting of a $32.4 million decrease in the fair value of open positions and $79.5 million of cash settlements paid on expired positions. Net losses on commodity derivative instruments of $98.5 million was recognized for the six months ended June 30, 2021, consisting of a $71.0 million decrease in the fair value of open positions and $27.5 million of cash settlements paid on expired positions.
36
Pipeline incident loss was $5.7 million for the six months ended June 30, 2022. The $5.7 million reflects legal expenses that the Company has determined will not be reimbursed through the insurance claims process. No expense was recorded for the six months ended June 30, 2021. See Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Interest expense, net was $5.5 million and $6.2 million for the six months ended June 30, 2022 and 2021, respectively. Interest expense included a gain position on our interest rate swaps of $0.8 million for the six months ended June 30, 2022, compared to a gain position on interest rate swaps of less than $0.1 million for the six months ended June 30, 2021. In addition, we had an increase of $0.1 million in interest expense due to higher rates on our Revolving Credit Facility.
Average outstanding borrowings under our Revolving Credit Facility were $223.7 million and $248.0 million for the six months ended June 30, 2022 and 2021, respectively.
Adjusted EBITDA
We include in this report the non-GAAP financial measure of Adjusted EBITDA and provide our reconciliation of Adjusted EBITDA to net income (loss) and net cash flows from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):
Plus:
| ● | Interest expense; |
| ● | Income tax expense; |
| ● | DDA; |
| ● | Impairment of goodwill and long-lived assets (including oil and natural gas properties); |
| ● | Accretion of AROs; |
| ● | Loss on commodity derivative instruments; |
| ● | Cash settlements received on expired commodity derivative instruments; |
| ● | Amortization of gain associated with terminated commodity derivatives; |
| ● | Losses on sale of assets; |
| ● | Share-based compensation expenses; |
| ● | Exploration costs; |
| ● | Acquisition and divestiture related expenses; |
| ● | Reorganization items, net; |
| ● | Severance payments; and |
| ● | Other non-routine items that we deem appropriate. |
37
Less:
| ● | Interest income; |
| ● | Income tax benefit; |
| ● | Gain on commodity derivative instruments; |
| ● | Cash settlements paid on expired commodity derivative instruments; |
| ● | Gains on sale of assets and other, net; and |
| ● | Other non-routine items that we deem appropriate. |
We believe that Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.
Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.
In addition, we use Adjusted EBITDA to evaluate actual cash flow available to develop existing reserves or acquire additional oil and natural gas properties.
The following tables present our reconciliation of the Company’s net income (loss ) and cash flows from operating activities to Adjusted EBITDA, our most directly comparable GAAP financial measures, for each of the periods indicated.
38
Reconciliation of Net Income (Loss) to Adjusted EBITDA
| For the Three Months Ended |
| For the Six Months Ended |
| |||||||||
| June 30, |
| June 30, |
| |||||||||
| 2022 |
| 2021 |
| 2022 |
| 2021 |
| |||||
| (In thousands) |
| |||||||||||
Net income (loss) | $ | 29,220 | $ | (35,023) | $ | (19,394) | $ | (54,351) | |||||
Interest expense, net |
| 3,084 |
| 3,137 |
| 5,525 |
| 6,249 | |||||
DDA |
| 5,864 |
| 7,389 |
| 11,499 |
| 14,736 | |||||
Accretion of AROs |
| 1,749 |
| 1,638 |
| 3,469 |
| 3,253 | |||||
Losses (gains) on commodity derivative instruments |
| 18,571 |
| 63,898 |
| 111,975 |
| 98,486 | |||||
Cash settlements (paid) received on expired commodity derivative instruments |
| (48,596) |
| (16,855) |
| (79,539) |
| (27,491) | |||||
Amortization of gain associated with terminated commodity derivatives | — | 4,166 | — | 9,951 | |||||||||
Pipeline incident loss |
| 5,092 |
| — |
| 5,672 |
| — | |||||
Acquisition and divestiture related expenses |
| 36 |
| 7 |
| 41 |
| 19 | |||||
Share-based compensation expense |
| 856 |
| 903 |
| 1,496 |
| 1,234 | |||||
Gain on extinguishment of debt |
| — |
| (5,516) |
| — |
| (5,516) | |||||
Exploration costs |
| 10 |
| 7 |
| 26 |
| 23 | |||||
Loss on settlement of AROs |
| 396 |
| 5 |
| 415 |
| 73 | |||||
Bad debt expense |
| (4) |
| 91 |
| 6 |
| 94 | |||||
Reorganization items, net | — | — | — | 6 | |||||||||
Other |
| — |
| — |
| — |
| 16 | |||||
Adjusted EBITDA | $ | 16,278 | $ | 23,847 | $ | 41,191 | $ | 46,782 | |||||
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
| For the Three Months Ended | For the Six Months Ended | |||||||||||
| June 30, | June 30, | |||||||||||
| 2022 |
| 2021 | 2022 |
| 2021 | |||||||
| (In thousands) | ||||||||||||
Net cash provided by operating activities | $ | 20,677 | $ | 20,845 | $ | 30,396 | $ | 36,403 | |||||
Changes in working capital |
| (13,582) |
| (4,526) |
| (2,209) |
| (7,248) | |||||
Interest expense, net |
| 3,084 |
| 3,137 |
| 5,525 |
| 6,249 | |||||
Gain (loss) on interest rate swaps |
| 286 |
| (18) |
| 843 |
| 44 | |||||
Cash settlements paid (received) on interest rate swaps |
| 93 |
| 476 |
| 307 |
| 940 | |||||
Amortization of gain associated with terminated commodity derivatives | — | 4,166 | — | 9,951 | |||||||||
Pipeline incident loss |
| 5,092 |
| — |
| 5,672 |
| — | |||||
Amortization and write-off of deferred financing fees |
| (203) |
| (221) |
| (336) |
| (360) | |||||
Acquisition and divestiture related expenses |
| 36 |
| 7 |
| 41 |
| 19 | |||||
Income tax expense - current portion |
| — |
| — |
| — |
| — | |||||
Exploration costs |
| 10 |
| 7 |
| 26 |
| 23 | |||||
Plugging and abandonment cost |
| 785 |
| 5 |
| 804 |
| 235 | |||||
Reorganization items, net |
| — |
| — |
| — |
| 6 | |||||
Other |
| — |
| (31) |
| 122 |
| 520 | |||||
Adjusted EBITDA | $ | 16,278 | $ | 23,847 | $ | 41,191 | $ | 46,782 | |||||
39
Liquidity and Capital Resources
Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities and borrowings under our Revolving Credit Facility. As we pursue reserve and production growth, we plan to monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our Revolving Credit Facility will provide us with the financial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2022 development activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. For the remainder of 2022, we expect our primary funding sources to be from internally generated cash flow, borrowings under our Revolving Credit Facility, and equity and debt capital markets.
Impact of the Southern California Pipeline Incident. There is substantial uncertainty surrounding the full impact that the Incident will have on our financial condition and cash flow generation going forward. We have incurred and will continue to incur costs as a result of the Incident, and we anticipate that the suspension of production from Beta will lead to a material reduction in revenue from these assets. Although we carry customary insurance policies, including loss of production income insurance, which we expect will cover a material portion of the total aggregate costs associated with the Incident, including loss of revenue resulting from suspended operations, we can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses related to the Incident.
Capital Markets. We do not currently anticipate any near-term capital markets activity, but we will continue to evaluate the availability of public debt and equity for funding potential future growth projects and acquisition activity.
Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 50%-60% of our estimated production from total proved developed producing reserves over a one-to-three-year period at any given point of time. We may, however, from time to time, hedge more or less than this approximate amount. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts.
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could also result in losses.
Capital Expenditures. Our total capital expenditures were approximately $20.4 million for the six months ended June 30, 2022, which were primarily related to capital workovers, maintenance and facilities located in Oklahoma, East Texas, the Rockies and non-operated drilling and completion activities in East Texas and the Eagle Ford.
Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable, as well as the classification of our debt outstanding. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.
40
As of June 30, 2022, we had a working capital deficit of $78.1 million primarily due to short-term derivatives of $80.0 million, accrued liabilities of $48.9 million, revenues payable of $24.5 million, and accounts payable of $35.0 million offset by accounts receivable of $77.8 million, cash on hand of $16.7 million and prepaid expenses of $15.2 million.
Debt Agreement
Revolving Credit Facility. On November 2, 2018, OLLC, as borrower, entered into the Revolving Credit Facility (as amended and supplemented to date). KeyBank serves as the administrative agent. Our borrowing base under our Revolving Credit Facility is subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report.
As of June 30, 2022, we had approximately $10.0 million of available borrowings under our Revolving Credit Facility.
As of June 30, 2022, we were in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with our Revolving Credit Facility.
On June 20, 2022, OLLC entered into the Sixth Amendment. The Sixth Amendment amends the Revolving Credit Facility to, among other things:
| ● | terminate the automatic monthly reductions of the borrowing base; |
| ● | reaffirm the borrowing base under the Revolving Credit Facility at $225.0 million; and |
| ● | modify the affirmative hedging covenant. |
For additional information regarding our Revolving Credit Facility, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Material Cash Requirements
Contractual commitments. We have contractual commitments under our debt agreements, including interest payments and principal payments. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Lease Obligations. We have operating leases for office and warehouse spaces, office equipment, compressors and surface rentals related to our business obligations. See Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Sinking fund payments. We have a funding requirement to fund a trust account to comply with supplemental regulatory bonding requirements related to our decommissioning obligations for our offshore Southern California production facilities. As of June 30, 2022, our future commitment under this agreement were $2.7 million for the remaining of 2022. See Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
41
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the six months ended June 30, 2022 and 2021 have been derived from our Unaudited Condensed Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see our Unaudited Condensed Consolidated Statements of Cash Flows included under “Item 1. Financial Statements” of this quarterly report.
| For the Six Months Ended | |||||
| June 30, | |||||
| 2022 |
| 2021 | |||
| (In thousands) | |||||
Net cash provided by operating activities | $ | 30,396 | $ | 36,403 | ||
Net cash used in investing activities |
| (16,914) |
| (11,575) | ||
Net cash used in financing activities |
| (15,590) |
| (20,042) | ||
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $30.4 million and $36.4 million for the six months ended June 30, 2022 and 2021, respectively. Production volumes were approximately 20.4 MBoe/d and 25.0 MBoe/d for the six months ended June 30, 2022 and 2021, respectively. The average realized sales price was $55.95 per Boe and $33.76 per Boe for the six months ended June 30, 2022 and 2021, respectively. The change in average realized sales price was primarily due to the increase in commodity prices.
Net cash provided by operating activities for the six months ended June 30, 2022 included $79.5 million of cash paid on expired commodity derivative instruments compared to $27.5 million of cash paid on expired commodity derivatives for the six months ended June 30, 2021. For the six months ended June 30, 2022, we had net losses on commodity derivative instruments of $112.0 million compared to net losses of $98.5 million for the six months ended June 30, 2021.
Investing Activities. Net cash used in investing activities for the six months ended June 30, 2022 was $16.9 million, of which $12.9 million was used for additions to oil and natural gas properties. Net cash provided by investing activities for the six months ended June 30, 2021 was $11.6 million, of which $11.5 million was used for additions to oil and natural gas properties.
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California properties. Additions to restricted investments were $4.0 million during the six months ended June 30, 2022.
Financing Activities. We had net repayments of $15.0 million and $20.0 million for the six months ended June 30, 2022 and 2021, respectively, related to our Revolving Credit Facility.
Off–Balance Sheet Arrangements
As of June 30, 2022, we had no off–balance sheet arrangements.
Recently Issued Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
42
ITEM 4.CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures
As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2022.
The full impact of COVID-19 on our business is still uncertain. In order to protect the health and safety of our employees, we took proactive steps to allow employees to work remotely and to reduce the number of employees on site at any one time in our field areas to comply with social distancing guidelines. We believe that our internal controls and procedures are still functioning as designed and were effective for the most recent quarter.
Change in Internal Control Over Financial Reporting
No changes in our internal control over financial reporting occurred during the most recent quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2, respectively, to this quarterly report.
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PART II—OTHER INFORMATION
ITEM 1.LEGAL PROCEEDINGS.
For a discussion of the legal proceedings associated with the Incident, see Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report and the annual financial statements and related notes included in our 2021 Form-10K.
Future litigation may be necessary, among other things, to defend ourselves by determining the scope, enforceability, and validity of claims. The results of any current or future litigation cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources, and other factors.
ITEM 1A.RISK FACTORS.
Our business faces many risks. Any of the risks discussed elsewhere in this quarterly report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. There have been no material changes to the risk factors since those disclosed in our 2021 Form 10-K.
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
The following table summarizes our repurchase activity during the three months ended June 30, 2022:
|
|
| Total Number of |
| Approximate Dollar | ||||
| Shares Purchased as |
| Value of Shares That | ||||||
| Part of Publicly |
| May Yet Be | ||||||
| Total Number of |
| Average Price |
| Announced Plans |
| Purchased Under the | ||
Period |
| Shares Purchased |
| Paid per Share |
| or Programs |
| Plans or Programs (1) | |
| (In thousands) | ||||||||
Common Shares Repurchased (1) |
|
|
|
|
|
|
|
| |
April 1, 2022 - April 30, 2022 |
| 2,304 | $ | 5.78 |
| — |
| n/a | |
May 1, 2022 - May 31, 2022 |
| — | $ | — |
| — |
| n/a | |
June 1, 2022 - June 30, 2022 |
| — | $ | — |
| — |
| n/a | |
| (1) | Common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. We repurchased the remaining vesting shares on the vesting date at current market price. See Note 8 of the Notes to the Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information. |
ITEM 3.DEFAULTS UPON SENIOR SECURITIES.
None.
ITEM 4.MINE SAFETY DISCLOSURES.
Not applicable.
ITEM 5.OTHER INFORMATION.
None.
44
ITEM 6.EXHIBITS.
Exhibit |
|
| Description | |
|---|---|---|---|---|
3.1 | — | |||
3.2 | — | |||
3.3 | — | |||
10.1 | — | |||
31.1* | — |
| ||
31.2* | — |
| ||
32.1** | — |
| ||
101.INS* | — |
| Inline XBRL Instance Document | |
101.SCH* | — |
| Inline XBRL Schema Document | |
101.CAL* | — |
| Inline XBRL Calculation Linkbase Document | |
101.DEF* | — |
| Inline XBRL Definition Linkbase Document | |
101.LAB* | — |
| Inline XBRL Labels Linkbase Document | |
101.PRE* | — |
| Inline XBRL Presentation Linkbase Document | |
104* | — | Cover Page Interactive Data File (embedded within the Inline XBRL document) |
* | Filed as an exhibit to this Quarterly Report on Form 10-Q. |
** | Furnished as an exhibit to this Quarterly Report on Form 10-Q. |
45
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Amplify Energy Corp. | |||
(Registrant) | |||
Date: | August 3, 2022 | By: | /s/ Jason McGlynn |
Name: | Jason McGlynn | ||
Title: | Senior Vice President and Chief Financial Officer | ||
Date: | August 3, 2022 | By: | /s/ Eric Dulany |
Name: | Eric Dulany | ||
Title: | Vice President and Chief Accounting Officer | ||
46