| | Delaware
| | 82-1326219 | (State or other jurisdiction of
incorporation or organization) | | 45-3691816
(I.R.S. Employer
Identification No.)
| | | | 321 South Boston Avenue, 500 Dallas Street, Suite 1000
Tulsa, Oklahoma1700
, Houston, TX
| | 77002 | (Address of principal executive offices) | | 74103
(Zip Code)
|
Registrant’s telephone number, including area code: (918) 947-8550(832) 219-9001 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes xþ No o☐ Indicate by check mark whether the registrant has submitted electronically, and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes xþ No o☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See 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 o☐ | | Accelerated fileroþ | Non-accelerated filer ☐ | | Smaller reporting company ☑ | Non-accelerated filer o
| | Smaller reporting company x
| (Do not check if a smaller reporting company)
| | Emerging growth company o☐ | |
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. o☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-212b–2 of the Exchange Act). Yes o☐ No xþ The numberIndicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of shares outstandingthe Securities Exchange Act of our stock at November 9, 2017 is shown below:1934 subsequent to the distribution of securities under a plan confirmed by a court. þ Yes ☐ No
Securities Registered Pursuant to Section 12(b): | | ClassTitle of each class
| Trading Symbol(s) | Name of each exchange on which registered | Common Stock | AMPY | NYSE |
As of April 30, 2024, the registrant had 39,612,030 outstanding shares of common stock, $0.01 par value outstanding. AMPLIFY ENERGY CORP. TABLE OF CONTENTS | | | | | |
| | | Number of shares outstandingPage
| Common stock, $0.01 par value
| | 25,173,346
|
DOCUMENTS INCORPORATED BY REFERENCE
None.
Table of Contents
MIDSTATES PETROLEUM COMPANY, INC.
QUARTERLY REPORT ON
FORM 10-Q
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2017
TABLE OF CONTENTS
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, ofor 42 U.S. gallons liquid volume, used herein in reference to oil condensate or natural gas liquids.other liquid hydrocarbons. Bbl/d: One Bbl per day. Boe: Barrels of oil equivalent, with 6,000Bcfe: One billion cubic feet of natural gas being equivalent to oneequivalent.
Boe: One barrel of oil. Boe/day: Barrels of oil equivalent, per day.
Completion: The processcalculated by converting natural gas to oil equivalent barrels at a ratio of treating a drilled well followed by the installation of permanent equipment for the productionsix Mcf of natural gas or oil, or into one Bbl of oil.
BOEM: U.S. Bureau of Ocean Energy Management. BSEE: Bureau of Safety and Environmental Enforcement. Btu: One British thermal unit, the casequantity of heat required to raise the temperature of a dry hole,one-pound mass of water by one degree Fahrenheit. CO2: Carbon dioxide. Development Project: A development project is the reporting of abandonmentmeans by which petroleum resources are brought to the appropriate agency.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: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 do notwould exceed production expenses and taxes. Exploratory well: A well drilledEconomically Producible: The term economically producible, as it relates to find a new fieldresource, means a resource which generates revenue that exceeds, or is reasonably expected to find a new reservoir in a field previously found to be productiveexceed, 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 in another reservoir.equivalent. MBoe/d: One thousand barrels of oil equivalent per day. MMBoe:One million barrels of oil equivalent. Mcf: One thousand cubic feet of natural gas. Mcf/d: One Mcf per day. MMBtu: One million British thermal units.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 acres:Production: Production that is owned by us less royalties and production due to others. NGLs: The percentagecombination of total acres an owner has outethane, propane, butane and natural gasolines that, when removed from natural gas, become liquid under various levels of a particular number of acres, or a specified tract.higher pressure and lower temperature. NYMEX: The 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 reserves: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—producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—regulations, prior to the time at which contracts providing the right to drill or operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including but not limited to, 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 12-monthtwelve-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. Reasonable certainty: A high degreeReliable Technology: Reliable technology is a grouping of confidence.
Recompletion: The process of re-entering an existing wellboreone or more technologies (including computational methods) that is either producinghas been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or not producing and completing new reservoirs in an attempt to establish, re-establishing, or increase existing production.analogous formation.
Reserves: Estimated 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 reservoirs.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. Spud or Spudding:SEC: The commencementU.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 operations of a new well.and production operations. Wellbore: The hole drilled by the bit that is equipped for oil or gas productionWorkover: Operations on a completed well. Also calledproducing well to restore or borehole.increase production.
WTI: West Texas Intermediate. Working interest: The right granted
NAMES OF ENTITIES As used in this Form 10-Q, unless indicated otherwise: | ● | “Amplify Energy,” “Amplify,” “it,” the “ Company,” “we,” “our,” “us,” or like terms refer to Amplify Energy Corp. individually and/or 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. |
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: | ● | acquisition and disposition strategy; |
| ● | cash flows and liquidity; |
| ● | ongoing impact of the oil incident that occurred off the coast of Southern California resulting from the Company’s pipeline operations (the “Pipeline”) at the Beta Field (the “Incident”); |
| ● | ability to replace the reserves we produce through drilling; |
| ● | oil and natural gas reserves; |
| ● | realized oil, natural gas and NGL prices; |
| ● | 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; |
| ● | political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns; |
| ● | acts of God, fires, earthquakes, storms, floods, other adverse weather conditions, war, acts of terrorism, cybersecurity breaches, military operations or national emergency; |
| ● | the occurrence or threat of epidemic or pandemic diseases, or any government response to such occurrence or threat; |
| ● | expectations regarding general economic conditions, including inflation; |
| ● | 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,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the lesseefollowing risks and uncertainties: | ● | risks related to a redetermination of the borrowing base under our senior secured reserve-based revolving credit facility (the “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; |
| ● | risks related to the Incident and the ongoing impact to the Company; |
| ● | volatility in the prices for oil, natural gas and NGLs; |
| ● | the potential for additional impairments due to continuing or future declines in oil, natural gas and NGL prices; |
| ● | the uncertainty inherent in estimating quantities of oil, natural gas and NGL reserves; |
| ● | our substantial future capital requirements, which may be subject to limited availability of financing; |
| ● | the uncertainty inherent in the development and production of oil and natural gas; |
| ● | our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base; |
| ● | the existence of unanticipated liabilities or problems relating to acquired or divested businesses or properties; |
| ● | potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties; |
| ● | the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity; |
| ● | potential shortages of, or increased costs for, drilling and production equipment and supply materials for production, such as CO2; |
| ● | potential difficulties in the marketing of oil and natural gas; |
| ● | changes to the financial condition of counterparties; |
| ● | uncertainties surrounding the success of our secondary and tertiary recovery efforts; |
| ● | competition in the oil and natural gas industry; |
| ● | our results of evaluation and implementation of strategic alternatives; |
| ● | general political and economic conditions, globally and in the jurisdictions in which we operate, including Russian invasion of Ukraine, the Israel-Hamas war and the potential 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 propertynumber of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to explorebe 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 andthe year ended December 31, 2023 filed with the SEC on March 7, 2024 (“2023 Form 10-K”). All forward-looking statements speak only as of the date of this report. The Company does not intend to produce and own oil, natural gas,update or other minerals. The working interest owners bearrevise 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 exploration, development, and operating costsCompany or persons acting on a cash, penalty, or carried basis.its behalf. PART I—FINANCIAL INFORMATION PART I — ITEM 1.FINANCIAL INFORMATIONSTATEMENTS.
AMPLIFY ENERGY CORP. MIDSTATES PETROLEUM COMPANY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share amounts)outstanding shares) | | | | | | | | | March 31, | | December 31, | | | 2024 | | 2023 | ASSETS | | | | | | | Current assets: | | | | | | | Cash and cash equivalents | | $ | 2,989 | | $ | 20,746 | Accounts receivable, net (see Note 12) | | | 36,540 | | | 39,096 | Short-term derivative instruments | | | 4,429 | | | 17,669 | Prepaid expenses and other current assets | | | 18,366 | | | 20,672 | Total current assets | | | 62,324 | | | 98,183 | Property and equipment, at cost: | | | | | | | Oil and natural gas properties, successful efforts method | | | 891,407 | | | 873,478 | Support equipment and facilities | | | 150,211 | | | 149,069 | Other | | | 11,038 | | | 10,359 | Accumulated depreciation, depletion and amortization | | | (694,405) | | | (686,165) | Property and equipment, net | | | 358,251 | | | 346,741 | Long-term derivative instruments | | | 1,778 | | | 9,405 | Restricted investments | | | 22,392 | | | 19,935 | Operating lease - long term right-of-use asset | | | 5,407 | | | 5,756 | Deferred tax asset | | | 258,498 | | | 253,796 | Other long-term assets | | | 3,554 | | | 3,858 | Total assets | | $ | 712,204 | | $ | 737,674 | | | | | | | | LIABILITIES AND EQUITY | | | | | | | Current liabilities: | | | | | | | Accounts payable | | $ | 21,723 | | $ | 23,616 | Revenues payable | | | 20,809 | | | 21,944 | Accrued liabilities (see Note 12) | | | 36,776 | | | 50,871 | Total current liabilities | | | 79,308 | | | 96,431 | Long-term debt (see Note 7) | | | 115,000 | | | 115,000 | Asset retirement obligations | | | 124,062 | | | 122,001 | Operating lease liability | | | 4,704 | | | 5,090 | Other long-term liabilities | | | 8,115 | | | 8,116 | Total liabilities | | | 331,189 | | | 346,638 | Commitments and contingencies (see Note 14) | | | | | | | Stockholders' equity (deficit): | | | | | | | Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding at March 31, 2024 and December 31, 2023 | | | — | | | — | Common stock, $0.01 par value: 250,000,000 shares authorized; 39,612,030 and 39,147,205 shares issued and outstanding at March 31, 2024 and December 31, 2023, respectively | | | 398 | | | 393 | Additional paid-in capital | | | 434,465 | | | 435,095 | Accumulated deficit | | | (53,848) | | | (44,452) | Total stockholders' equity (deficit) | | | 381,015 | | | 391,036 | Total liabilities and equity | | $ | 712,204 | | $ | 737,674 |
| | September 30, 2017 | | December 31, 2016 | | ASSETS | | | | | | CURRENT ASSETS: | | | | | | Cash and cash equivalents | | $ | 76,548 | | $ | 76,838 | | Accounts receivable: | | | | | | Oil and gas sales | | 29,776 | | 36,988 | | Joint interest billing | | 3,193 | | 4,281 | | Other | | 630 | | 2,456 | | Commodity derivative contracts | | 2,896 | | — | | Other current assets | | 1,821 | | 3,326 | | Total current assets | | 114,864 | | 123,889 | | PROPERTY AND EQUIPMENT: | | | | | | Oil and gas properties, on the basis of full-cost accounting | | | | | | Proved properties | | 709,647 | | 573,150 | | Unproved properties not being amortized | | 26,178 | | 65,080 | | Other property and equipment | | 6,543 | | 6,339 | | Less accumulated depreciation, depletion and amortization | | (59,349 | ) | (12,974 | ) | Net property and equipment | | 683,019 | | 631,595 | | OTHER NONCURRENT ASSETS | | 7,156 | | 5,455 | | TOTAL | | $ | 805,039 | | $ | 760,939 | | | | | | | | LIABILITIES AND EQUITY | | | | | | CURRENT LIABILITIES: | | | | | | Accounts payable | | $ | 9,480 | | $ | 2,521 | | Accrued liabilities | | 46,987 | | 53,731 | | Total current liabilities | | 56,467 | | 56,252 | | LONG-TERM LIABILITIES: | | | | | | Asset retirement obligations | | 14,039 | | 14,200 | | Commodity derivative contracts | | 278 | | — | | Long-term debt | | 128,059 | | 128,059 | | Other long-term liabilities | | 599 | | 614 | | Total long-term liabilities | | 142,975 | | 142,873 | | | | | | | | COMMITMENTS AND CONTINGENCIES (Note 14) | | | | | | | | | | | | STOCKHOLDERS’ EQUITY: | | | | | | Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at September 30, 2017 and December 31, 2016 | | — | | — | | Warrants, 6,625,554 warrants outstanding at September 30, 2017 and December 31, 2016 | | 37,329 | | 37,329 | | Common stock, $0.01 par value, 250,000,000 shares authorized; 25,098,834 shares issued and 25,065,425 shares outstanding at September 30, 2017 and 24,994,867 shares issued and outstanding at December 31, 2016 | | 251 | | 250 | | Treasury stock | | (626 | ) | — | | Additional paid-in-capital | | 522,823 | | 514,305 | | Retained earnings | | 45,820 | | 9,930 | | Total stockholders’ equity | | 605,597 | | 561,814 | | TOTAL | | $ | 805,039 | | $ | 760,939 | |
The accompanying notes are an integral partSee Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
AMPLIFY ENERGY CORP.
MIDSTATES PETROLEUM COMPANY, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share amounts) | | Successor | | | Predecessor | | Successor | | | Predecessor | | | | For the Three
Months Ended | | | For the Three
Months Ended | | For the Nine
Months Ended | | | For the Nine
Months Ended | | | | September 30, 2017 | | | September 30, 2016 | | September 30, 2017 | | | September 30, 2016 | | REVENUES: | | | | | | | | | | | | Oil sales | | $ | 27,190 | | | $ | 35,584 | | $ | 85,497 | | | $ | 104,832 | | Natural gas liquid sales | | 10,656 | | | 8,939 | | 31,580 | | | 25,073 | | Natural gas sales | | 13,970 | | | 17,676 | | 46,321 | | | 44,486 | | Gains (losses) on commodity derivative contracts—net | | (3,591 | ) | | — | | 8,767 | | | — | | Other | | 1,490 | | | 1,994 | | 3,244 | | | 4,322 | | Total revenues | | 49,715 | | | 64,193 | | 175,409 | | | 178,713 | | EXPENSES: | | | | | | | | | | | | Lease operating and workover | | 15,653 | | | 17,650 | | 48,064 | | | 49,520 | | Gathering and transportation | | 3,699 | | | 4,296 | | 11,027 | | | 13,428 | | Severance and other taxes | | 2,352 | | | 1,788 | | 6,168 | | | 4,776 | | Asset retirement accretion | | 274 | | | 452 | | 833 | | | 1,316 | | Depreciation, depletion, and amortization | | 15,170 | | | 15,756 | | 46,471 | | | 59,229 | | Impairment in carrying value of oil and gas properties | | — | | | 33,887 | | — | | | 224,584 | | General and administrative | | 7,255 | | | 3,308 | | 23,102 | | | 19,093 | | Debt restructuring costs and advisory fees | | — | | | — | | — | | | 7,589 | | Total expenses | | 44,403 | | | 77,137 | | 135,665 | | | 379,535 | | OPERATING INCOME (LOSS) | | 5,312 | | | (12,944 | ) | 39,744 | | | (200,822 | ) | OTHER EXPENSE: | | | | | | | | | | | | Interest income | | — | | | — | | — | | | 81 | | Interest expense—net of amounts capitalized (excludes interest expense of $47.6 million and $79.3 million on senior and secured notes subject to compromise for the three and nine months ended September 30, 2016, respectively) | | (1,649 | ) | | (2,668 | ) | (3,854 | ) | | (65,719 | ) | Reorganization items, net | | — | | | (22,772 | ) | — | | | 57,764 | | Total other expense | | (1,649 | ) | | (25,440 | ) | (3,854 | ) | | (7,874 | ) | INCOME (LOSS) BEFORE TAXES | | 3,663 | | | (38,384 | ) | 35,890 | | | (208,696 | ) | Income tax expense | | — | | | — | | — | | | — | | NET INCOME (LOSS) | | $ | 3,663 | | | $ | (38,384 | ) | $ | 35,890 | | | $ | (208,696 | ) | Successor participating securities—non-vested restricted stock | | (82 | ) | | — | | (932 | ) | | — | | Predecessor participating securities—non-vested restricted stock | | — | | | — | | — | | | — | | NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | | $ | 3,581 | | | $ | (38,384 | ) | $ | 34,958 | | | $ | (208,696 | ) | Basic and diluted net income (loss) per share attributable to common shareholders | | $ | 0.14 | | | $ | (3.60 | ) | $ | 1.39 | | | $ | (19.61 | ) | Basic and diluted weighted average number of common shares outstanding (Note 12) | | 25,116 | | | 10,657 | | 25,074 | | | 10,644 | |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
| | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | Revenues: | | | | | | | Oil and natural gas sales | | $ | 75,322 | | $ | 66,284 | Other revenues | | | 977 | | | 13,586 | Total revenues | | | 76,299 | | | 79,870 | | | | | | | | Costs and expenses: | | | | | | | Lease operating expense | | | 38,284 | | | 32,960 | Gathering, processing and transportation | | | 4,774 | | | 5,602 | Taxes other than income | | | 4,911 | | | 5,293 | Depreciation, depletion and amortization | | | 8,239 | | | 5,808 | General and administrative expense | | | 9,800 | | | 8,514 | Accretion of asset retirement obligations | | | 2,061 | | | 1,942 | Loss (gain) on commodity derivative instruments | | | 16,564 | | | (15,159) | Pipeline incident loss | | | 707 | | | 8,279 | Other, net | | | 41 | | | 26 | Total costs and expenses | | | 85,381 | | | 53,265 | Operating income (loss) | | | (9,082) | | | 26,605 | Other income (expense): | | | | | | | Interest expense, net | | | (3,527) | | | (5,737) | Litigation settlement (See Note 16) | | | — | | | 84,875 | Other income (expense) | | | (95) | | | 73 | Total other income (expense) | | | (3,622) | | | 79,211 | Income (loss) before income taxes | | | (12,704) | | | 105,816 | Income tax (expense) benefit - current | | | (1,395) | | | (12,527) | Income tax (expense) benefit - deferred | | | 4,703 | | | 259,470 | Net income (loss) | | $ | (9,396) | | $ | 352,759 | | | | | | | | Allocation of net income (loss) to: | | | | | | | Net income (loss) available to common stockholders | | $ | (9,396) | | $ | 336,373 | Net income (loss) allocated to participating securities | | | — | | | 16,386 | Net income (loss) available to Amplify Energy Corp. | | $ | (9,396) | | $ | 352,759 | | | | | | | | Earnings (loss) per share: (See Note 9) | | | | | | | Basic and diluted earnings (loss) per share | | $ | (0.24) | | $ | 8.69 | Weighted average common shares outstanding: | | | | | | | Basic and diluted | | | 39,410 | | | 38,694 |
MIDSTATES PETROLEUM COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY/(DEFICIT)
(Unaudited)
(In thousands)
| | Series A
Preferred
Stock | | Common
Stock | | Warrants | | Treasury
Stock | | Additional
Paid-in-Capital | | Retained
Earnings | | Total
Stockholders’
Equity | | Balance as of December 31, 2016 (Successor) | | $ | — | | $ | 250 | | $ | 37,329 | | $ | — | | $ | 514,305 | | $ | 9,930 | | $ | 561,814 | | Share-based compensation | | — | | 1 | | — | | — | | 8,518 | | — | | 8,519 | | Acquisition of treasury stock | | — | | — | | — | | (626 | ) | — | | — | | (626 | ) | Net income | | — | | — | | — | | — | | — | | 35,890 | | 35,890 | | Balance as of September 30, 2017 (Successor) | | $ | — | | $ | 251 | | $ | 37,329 | | $ | (626 | ) | $ | 522,823 | | $ | 45,820 | | $ | 605,597 | | | | | | | | | | | | | | | | | | | | Series A
Preferred
Stock | | Common
Stock | | Warrants | | Treasury
Stock | | Additional
Paid-in-Capital | | Retained
Deficit | | Total
Stockholders’
Deficit | | Balance as of December 31, 2015 (Predecessor) | | $ | — | | $ | 110 | | $ | — | | $ | (3,081 | ) | $ | 888,247 | | $ | (2,211,342 | ) | $ | (1,326,066 | ) | Share-based compensation | | — | | (1 | ) | — | | — | | 1,726 | | — | | 1,725 | | Acquisition of treasury stock | | — | | — | | — | | (53 | ) | — | | — | | (53 | ) | Net loss | | — | | — | | — | | — | | — | | (208,696 | ) | (208,696 | ) | Balance as of September 30, 2016 (Predecessor) | | $ | — | | $ | 109 | | $ | — | | $ | (3,134 | ) | $ | 889,973 | | $ | (2,420,038 | ) | $ | (1,533,090 | ) |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
MIDSTATES PETROLEUM COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
| | Successor | | | Predecessor | | | | For the Nine Months
Ended | | | For the Nine Months
Ended | | | | September 30, 2017 | | | September 30, 2016 | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income (loss) | | $ | 35,890 | | | $ | (208,696 | ) | Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | Gains on commodity derivative contracts—net | | (8,767 | ) | | — | | Net cash received for commodity derivative contracts not designated as hedging instruments | | 6,149 | | | — | | Asset retirement accretion | | 833 | | | 1,316 | | Depreciation, depletion, and amortization | | 46,471 | | | 59,229 | | Impairment in carrying value of oil and gas properties | | — | | | 224,584 | | Share-based compensation, net of amounts capitalized to oil and gas properties | | 7,102 | | | 1,275 | | Amortization of deferred financing costs | | 277 | | | 4,495 | | Paid-in-kind interest expense | | — | | | 3,531 | | Amortization of deferred gain on debt restructuring | | — | | | (8,246 | ) | Operating lease abandonment | | — | | | 1,574 | | Noncash reorganization items | | — | | | (70,489 | ) | Change in operating assets and liabilities: | | | | | | | Accounts receivable—oil and gas sales | | 4,929 | | | (311 | ) | Accounts receivable—JIB and other | | 2,641 | | | 21,411 | | Other current and noncurrent assets | | (98 | ) | | (5,572 | ) | Accounts payable | | 1,392 | | | 870 | | Accrued liabilities | | (7,381 | ) | | 54,520 | | Other | | (121 | ) | | (1,247 | ) | Net cash provided by operating activities | | $ | 89,317 | | | $ | 78,244 | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | Investment in property and equipment | | $ | (92,841 | ) | | $ | (129,072 | ) | Proceeds from the sale of oil and gas equipment and properties | | 4,235 | | | — | | Net cash used in investing activities | | $ | (88,606 | ) | | $ | (129,072 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | Proceeds from revolving credit facility | | — | | | 249,384 | | Deferred financing costs | | (375 | ) | | — | | Acquisition of treasury stock | | (626 | ) | | (53 | ) | Net cash (used in) provided by financing activities | | $ | (1,001 | ) | | $ | 249,331 | | NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | | $ | (290 | ) | | $ | 198,503 | | Cash and cash equivalents, beginning of period | | $ | 76,838 | | | $ | 81,093 | | Cash and cash equivalents, end of period | | $ | 76,548 | | | $ | 279,596 | | | | | | | | | SUPPLEMENTAL INFORMATION: | | | | | | | Non-cash transactions — investments in property and equipment accrued — not paid | | $ | 19,865 | | | $ | 12,238 | | Cash paid for interest, net of capitalized interest of $2.1 million for the nine months ended September 30, 2017 (no capitalized interest for the nine months ended September 30, 2016) | | $ | 3,708 | | | $ | 5,821 | | Cash paid for reorganization items | | $ | — | | | $ | 12,725 | |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
MIDSTATES PETROLEUM COMPANY, INC.
See Accompanying Notes to Unaudited Condensed Consolidated Financial StatementsStatements. AMPLIFY ENERGY CORP. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) | | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | Cash flows from operating activities: | | | | | | | Net income (loss) | | $ | (9,396) | | $ | 352,759 | Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | Depreciation, depletion and amortization | | | 8,239 | | | 5,808 | Loss (gain) on derivative instruments | | | 16,564 | | | (15,159) | Cash settlements (paid) received on expired derivative instruments | | | 4,303 | | | (2,709) | Deferred income tax expense (benefit) | | | (4,703) | | | (259,470) | Accretion of asset retirement obligations | | | 2,061 | | | 1,942 | Share-based compensation (see Note 10) | | | 1,531 | | | 941 | Amortization and write-off of deferred financing costs | | | 304 | | | 461 | Bad debt expense | | | 26 | | | — | Changes in operating assets and liabilities: | | | | | | | Accounts receivable | | | 2,530 | | | 14,476 | Prepaid expenses and other assets | | | 2,306 | | | 2,450 | Payables and accrued liabilities | | | (16,053) | | | (10,940) | Other | | | — | | | (246) | Net cash provided by operating activities | | | 7,712 | | | 90,313 | Cash flows from investing activities: | | | | | | | Additions to oil and gas properties | | | (20,589) | | | (8,187) | Additions to other property and equipment | | | (679) | | | (150) | Additions to restricted investments | | | (2,456) | | | (2,080) | Net cash used in investing activities | | | (23,724) | | | (10,417) | Cash flows from financing activities: | | | | | | | Advances on Revolving Credit Facility | | | 25,000 | | | 10,000 | Payments on Revolving Credit Facility | | | (25,000) | | | (75,000) | Shares withheld for taxes | | | (1,745) | | | (2,141) | Net cash used in financing activities | | | (1,745) | | | (67,141) | Net change in cash and cash equivalents | | | (17,757) | | | 12,755 | Cash and cash equivalents, beginning of period | | | 20,746 | | | — | Cash and cash equivalents, end of period | | $ | 2,989 | | $ | 12,755 |
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements. AMPLIFY ENERGY CORP. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (DEFICIT) (In thousands) | | | | | | | | | | | | | | | Stockholders' Equity | | | | | | Additional | | Accumulated | | | | | | Common | | Paid-in | | Earnings | | | | | | Stock | | Capital | | (Deficit) | | Total | Balance at December 31, 2023 | | $ | 393 | | $ | 435,095 | | $ | (44,452) | | $ | 391,036 | Net income (loss) | | | — | | | — | | | (9,396) | | | (9,396) | Share-based compensation expense | | | — | | | 1,120 | | | — | | | 1,120 | Shares withheld for taxes | | | — | | | (1,745) | | | — | | | (1,745) | Other | | | 5 | | | (5) | | | — | | | — | Balance at March 31, 2024 | | $ | 398 | | $ | 434,465 | | $ | (53,848) | | $ | 381,015 |
| | | | | | | | | | | | | | | Stockholders' Equity (Deficit) | | | | | | Additional | | Accumulated | | | | | Common | | Paid-in | | Earnings | | | | | | Stock | | Capital | | (Deficit) | | Total | Balance at December 31, 2022 | | $ | 386 | | $ | 432,251 | | $ | (437,202) | | $ | (4,565) | Net income (loss) | | | — | | | — | | | 352,759 | | | 352,759 | Share-based compensation expense | | | — | | | 941 | | | — | | | 941 | Shares withheld for taxes | | | — | | | (2,141) | | | — | | | (2,141) | Other | | | 5 | | | (5) | | | — | | | — | Balance at March 31, 2023 | | $ | 391 | | $ | 431,046 | | $ | (84,443) | | $ | 346,994 |
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements. Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 1. Organization and BusinessBasis of Presentation General Midstates Petroleum Company, Inc. engages inAmplify Energy Corp. (“Amplify Energy,” “Amplify,” “it” or the business of exploring and drilling for, and“Company”) is a publicly traded Delaware corporation whose common stock is listed on the production of, oil, natural gas liquids (“NGLs”) and natural gas in Oklahoma and Texas. Midstates Petroleum Company, Inc. was incorporated pursuant toNYSE under the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”). The terms “Company,symbol “AMPY.” “we,” “us,” “our,” and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary.
The Company operates a significant portionin one reportable segment that is engaged in the acquisition, development, exploitation and production of its oil and natural gas properties. The Company’s management evaluates performance based on one reportable business segment as allthere are not different economic environments within the operation of its operationsthe Company’s oil and natural gas properties. The Company’s assets consist primarily of producing oil and natural gas properties located in Oklahoma, the Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana and the Eagle Ford (non-op). Most of the Company’s oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. Basis of Presentation The Company’s accompanying Unaudited Condensed Consolidated Financial Statements include the United States and, therefore, it maintains one cost center. On April 30, 2016,accounts of the Company filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Company’s Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the case styled In re Midstates Petroleum Company, Inc., et al., Case No. 16-32237. On September 28, 2016, the Bankruptcy Court entered the Findings of Fact, Conclusions of Law, and Order Confirming Debtors’ First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate (the “Confirmation Order”),wholly owned subsidiaries which approved and confirmed the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on the same date (the “Plan”). On October 21, 2016 (the “Effective Date”), the Company satisfied the conditions to effectiveness set forth in the Confirmation Order and in the Plan, and, as a result, the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 Cases.
2. Summary of Significant Accounting Policies
Basis of Presentation
These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required byin accordance with accounting principles generally accepted in the United States of America (“US GAAP”). In the Company’s opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments of a normal recurring nature necessary for complete consolidatedfair 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 audited consolidatedCompany’s annual financial statements and notes thereto for the year ended December 31, 2016 included in the Company’s Annual Report onits 2023 Form 10-K as filed with the SEC on March 30, 2017.10-K. Use of Estimates All intercompany transactions have been eliminated in consolidation. In the opinionThe preparation of the Company’saccompanying Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying unaudited condensed consolidated financial statements, management has made certainmake estimates and assumptions that affect the reported amounts inof assets and liabilities and disclosure of contingent assets and liabilities at the unaudited condenseddate of the consolidated financial statements and disclosuresthe reported amounts of contingencies.revenues and expenses during the reporting period. Actual results maycould differ from those estimates. The results for interim periods
Significant estimates include, but are not necessarily indicativelimited to, oil and natural gas reserves; fair value estimates; revenue recognition; and contingencies and insurance accounting. Note 2. Summary of annual results.Significant Accounting Policies In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852, Reorganizations,There have been no changes to the Company adopted fresh startCompany’s significant accounting upon emergence from the Chapter 11 Cases resultingpolicies as described in the Company becoming a new entity for financial reporting purposes. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the Company’s consolidatedannual financial statements on or after October 21, 2016,included in its 2023 Form 10-K.
New Accounting Pronouncements The Company has implemented all new accounting pronouncements that are in effect. These pronouncements did not comparable with the consolidated financial statements prior to that date. References to “Successor Period” relate to the results of operations for the period January 1, 2017 through September 30, 2017 and references to “Predecessor Period” refer to the results of operations from January 1, 2016 through September 30, 2016. Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information inhave any material impact on the financial statements regardingunless otherwise disclosed, and the nature, timing and uncertainty of revenues. The Company has completed its review of contracts for each revenue stream identified within the Company’s business and is currently finalizing its conclusion on any changes in revenue recognition upon adoption of the revised guidance. Based on assessments to date, the Company believes ASU 2014-09 will impact the presentation of future revenues and expenses by including certain transportation and gathering costs, along with various other fees such as compression and marketing fees net within revenues. The inclusion of these costs within revenues will not impact the Company’s revenue recognition, its financial position, net income or cash flows. In addition, several industry interpretations are currently open for public comment. The Company cannot quantitatively assess the impact of ASU 2014-09 on its financial statements until final consensus is reached on these various industry matters. Once all pending industry interpretations are addressed, the Company will finalize its assessment of ASU 2014-09. The Company is in the process of evaluating the information technology and internal control changes that will be required for adoption based on the Company’s contract review process, but does not currently anticipate material impacts to either information technology or internal controls. However, this assessment is pending conclusion of various industry interpretations. The Company intends to apply the modified retrospective approach upon adoption of this standard on the effective date of January 1, 2018.
In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is in the initial evaluation and planning stages for ASU 2016-02 and does not expect to move beyond this stage until completion of its evaluation of ASU 2014-09.
In July 2017, the FASB issued Accounting Standards Update 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 willthat there are any other new accounting pronouncements that have been issued that might have a material impact on its financial position or results of operationsoperations.
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 three material revenue streams in its business: oil, natural gas and NGLs. The following table presents the Company’s revenues disaggregated by revenue stream. | | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | | | | (In thousands) | Revenues | | | | | | | Oil | | $ | 57,422 | | $ | 38,816 | NGLs | | | 7,525 | | | 7,785 | Natural gas | | | 10,375 | | | 19,683 | Oil and natural gas sales | | $ | 75,322 | | $ | 66,284 |
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 cash flows.liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers were $31.6 million at March 31, 2024 and $31.1 million at December 31, 2023. 3.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. Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 March 31, 2024 and December 31, 2023. 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 Derivative Instruments
Commodity derivative contracts reflected in the unaudited condensed consolidated balance sheets are recorded at estimatedThe fair value. At September 30, 2017, allmarket values of the Company’sderivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of March 31, 2024 and December 31, 2023 were based on estimated forward commodity derivative contracts were with four bank counterpartiesprices. Financial assets and wereliabilities are classified as Level 2 inbased on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input hierarchy. Theto the fair value ofmeasurement requires judgment and may affect the Company’s commodity derivatives are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially allvaluation of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
Derivative instruments listed below are presented gross and include swaps and collars that are carried at fair value. The Company records the net change in the fair value of these positions in “Gains (losses)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 commodity derivative contracts — net” ina recurring basis at March 31, 2024 and December 31, 2023 for each of the fair value hierarchy levels: | | | | | | | | | | | | | | | Fair Value Measurements at March 31, 2024 | | | | | | | 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 | | $ | — | | $ | 25,306 | | $ | — | | $ | 25,306 | Interest rate derivatives | | | — | | | — | | | — | | | — | Total assets | | $ | — | | $ | 25,306 | | $ | — | | $ | 25,306 | | | | | | | | | | | | | | Liabilities: | | | | | | | | | | | | | Commodity derivatives | | $ | — | | $ | 19,099 | | $ | — | | $ | 19,099 | Interest rate derivatives | | | — | | | — | | | — | | | — | Total liabilities | | $ | — | | $ | 19,099 | | $ | — | | $ | 19,099 |
| | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2023 | | | | | | | 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 | | $ | — | | $ | 39,439 | | $ | — | | $ | 39,439 | Interest rate derivatives | | | — | | | — | | | — | | | — | Total assets | | $ | — | | $ | 39,439 | | $ | — | | $ | 39,439 | | | | | | | | | | | | | | Liabilities: | | | | | | | | | | | | | Commodity derivatives | | $ | — | | $ | 12,365 | | $ | — | | $ | 12,365 | Interest rate derivatives | | | — | | | — | | | — | | | — | Total liabilities | | $ | — | | $ | 12,365 | | $ | — | | $ | 12,365 |
See Note 5 for additional information regarding the Company’s unaudited condensed consolidated statementsderivative 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). |
| ● | No impairment expense was recorded on proved oil and natural gas properties during the three months ended March 31, 2024 and 2023. |
| | Fair Value Measurements at September 30, 2017 | | | | | | Significant Other | | Significant | | | | | | Quoted Prices in Active
Markets (Level 1) | | Observable Inputs
(Level 2) | | Unobservable Inputs
(Level 3) | | Total | | | | (in thousands) | | Derivative Assets: | | | | | | | | | | Commodity derivative oil swaps | | $ | — | | $ | 722 | | $ | — | | $ | 722 | | Commodity derivative gas swaps | | $ | — | | $ | 1,006 | | $ | — | | $ | 1,006 | | Commodity derivative oil collars | | $ | — | | $ | 2,356 | | $ | — | | $ | 2,356 | | Commodity derivative gas collars | | $ | — | | $ | 2,806 | | $ | — | | $ | 2,806 | | Total assets | | $ | — | | $ | 6,890 | | $ | — | | $ | 6,890 | | | | | | | | | | | | Derivative Liabilities: | | | | | | | | | | Commodity derivative oil swaps | | $ | — | | $ | (772 | ) | $ | — | | $ | (772 | ) | Commodity derivative gas swaps | | $ | — | | $ | — | | $ | — | | $ | — | | Commodity derivative oil collars | | $ | — | | $ | (1,380 | ) | $ | — | | $ | (1,380 | ) | Commodity derivative gas collars | | $ | — | | $ | (2,120 | ) | $ | — | | $ | (2,120 | ) | Total liabilities | | $ | — | | $ | (4,272 | ) | $ | — | | $ | (4,272 | ) |
At December 31, 2016, the Company did not have any open commodity derivative contract positions.
4.Note 5. Risk Management and Derivative Instruments
The Company’s production is exposedDerivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and to achieve a more predictable cash flow in crude oil, NGLs andconnection with natural gas prices. The Company believes it is prudentand oil sales and borrowing related activities. These instruments limit exposure to managedeclines in prices but also limit the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude oil, NGLs and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices.benefits that would be realized if prices increase.
· Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price paymentCertain inherent business risks are netted, resulting in a net amount due to or from the counterparty.
· Collars: A collar contains a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
· Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price.
These derivative contracts are placedassociated with major financial institutions that the Company believes are minimal credit risks. The crude oil, NGLs and natural gas reference prices upon which the commodity derivative contracts, are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude oil, NGLs and natural gas production.
Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commoditynatural 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 Company’s counterparty to a contract. The Company doesIt is the Company’s policy to enter into derivative contracts only with creditworthy counterparties, which are generally 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 require collateral from itsrequired to be posted by counterparties, but does attempt to minimize its 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, which management believes present minimal credit risk. In addition,institutions. Additionally, master netting agreements are used to mitigate its 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 has entered into agreements withand each of its counterparties with rights of its derivative instruments that allowset-off upon the Company to offset its asset position with its liability position in the eventoccurrence of defined acts of default by either the counterparty. DueCompany or its counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the netting arrangements,defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, the Company would have the right to offset $7.6 million against amounts outstanding under our Revolving Credit Facility at March 31, 2024. See Note 7 for additional information regarding the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at September 30, 2017 would have been $2.6 million.Revolving Credit Facility.
Commodity Derivative Contracts Derivatives The Company has enteredmay 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. Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The Company enters into various oil and natural gas derivative contracts that extend through March 2019, summarized as follows: | | NYMEX WTI | | | | Fixed Swaps | | Collars | | Three Way Collars | | | | Hedge
Position
(Bbls) | | Weighted
Avg
Strike
Price | | Hedge
Position
(Bbls) | | Weighted
Avg Ceiling
Price | | Weighted
Avg Floor
Price | | Hedge
Position
(Bbls) | | Weighted
Avg
Ceiling
Price | | Weighted
Avg Floor
Price | | Weighted
Avg
Sub-Floor
Price | | Quarter Ended: | | | | | | | | | | | | | | | | | | | | September 30, 2017(2) | | 207,000 | | $ | 55.29 | | 46,000 | | $ | 60.00 | | $ | 50.00 | | 115,000 | | $ | 62.80 | | $ | 50.00 | | $ | 40.00 | | December 31, 2017(1)(2) | | 276,000 | | $ | 53.58 | | 46,000 | | $ | 60.00 | | $ | 50.00 | | 115,000 | | $ | 62.80 | | $ | 50.00 | | $ | 40.00 | | March 31, 2018(1) | | 99,000 | | $ | 50.61 | | — | | $ | — | | $ | — | | 225,000 | | $ | 62.14 | | $ | 50.00 | | $ | 40.00 | | June 30, 2018(1) | | 145,600 | | $ | 51.22 | | — | | $ | — | | $ | — | | 182,000 | | $ | 60.65 | | $ | 50.00 | | $ | 40.00 | | September 30, 2018(1) | | 92,000 | | $ | 50.38 | | — | | $ | — | | $ | — | | 184,000 | | $ | 59.93 | | $ | 50.00 | | $ | 40.00 | | December 31, 2018(1) | | 92,000 | | $ | 50.38 | | — | | $ | — | | $ | — | | 46,000 | | $ | 56.70 | | $ | 50.00 | | $ | 40.00 | | | | | | | | | | | | | | | | | | | | | | | | NYMEX HENRY HUB | | | | Fixed Swaps | | Collars | | Three Way Collars | | | | Hedge
Position
(MMBtu) | | Weighted
Avg Strike
Price | | Hedge
Position
(MMBtu) | | Weighted
Avg Ceiling
Price | | Weighted
Avg Floor
Price | | Hedge
Position
(MMBtu) | | Weighted
Avg
Ceiling
Price | | Weighted
Avg
Floor
Price | | Weighted
Avg
Sub-Floor
Price | | Quarter Ended: | | | | | | | | | | | | | | | | | | | | September 30, 2017 | | 2,944,000 | | $ | 3.38 | | 368,000 | | $ | 3.63 | | $ | 3.15 | | — | | $ | — | | $ | — | | $ | — | | December 31, 2017(1) | | 1,907,000 | | $ | 3.43 | | 551,000 | | $ | 3.84 | | $ | 3.23 | | 610,000 | | $ | 4.30 | | $ | 3.25 | | $ | 2.50 | | March 31, 2018(1)(3) | | 1,350,000 | | $ | 3.47 | | — | | $ | — | | $ | — | | 1,530,000 | | $ | 4.38 | | $ | 3.25 | | $ | 2.50 | | June 30, 2018(1) | | — | | $ | — | | — | | $ | — | | $ | — | | 1,365,000 | | $ | 3.40 | | $ | 3.00 | | $ | 2.50 | | September 30, 2018(1) | | — | | $ | — | | — | | $ | — | | $ | — | | 1,380,000 | | $ | 3.40 | | $ | 3.00 | | $ | 2.50 | | December 31, 2018(1) | | — | | $ | — | | — | | $ | — | | $ | — | | 1,380,000 | | $ | 3.40 | | $ | 3.00 | | $ | 2.50 | | March 31, 2019(1) | | — | | $ | — | | — | | $ | — | | $ | — | | 1,350,000 | | $ | 3.40 | | $ | 3.00 | | $ | 2.50 | |
(1) Positions shown represent open commodity derivative contract positions as of September 30, 2017.are indexed to NYMEX-Henry Hub. The Company did not have any open commodity derivative contract positions as of December 31, 2016.
(2) During the second quarter, the Company enteredalso enters into long call oil trades to offset its three way collar short calls for the second half of 2017.
(3) During the second quarter, the Company entered into natural gas three way collars with long call ceilings in order to offset its Q1 2018 natural gas fixed swaps.
Subsequent to September 30, 2017, the Company entered into various oil derivative contracts that extend through December 2019, summarized as follows:indexed to NYMEX-WTI.
At March 31, 2024, the Company had the following open commodity positions: | | NYMEX WTI | | | | Fixed Swaps | | Collars | | Three Way Collars | | | | Hedge
Position
(Bbls) | | Weighted
Avg
Strike
Price | | Hedge
Position
(Bbls) | | Weighted
Avg Ceiling
Price | | Weighted
Avg Floor
Price | | Hedge
Position
(Bbls) | | Weighted
Avg
Ceiling
Price | | Weighted
Avg Floor
Price | | Weighted
Avg
Sub-Floor
Price | | Quarter Ended: | | | | | | | | | | | | | | | | | | | | March 31, 2019 | | — | | $ | — | | — | | $ | — | | $ | — | | 45,000 | | $ | 56.20 | | $ | 50.00 | | $ | 40.00 | | June 30, 2019 | | — | | $ | — | | — | | $ | — | | $ | — | | 45,500 | | $ | 56.20 | | $ | 50.00 | | $ | 40.00 | | September 30, 2019 | | — | | $ | — | | — | | $ | — | | $ | — | | 46,000 | | $ | 56.20 | | $ | 50.00 | | $ | 40.00 | | December 31, 2019 | | — | | $ | — | | — | | $ | — | | $ | — | | 46,000 | | $ | 56.20 | | $ | 50.00 | | $ | 40.00 | |
| | | | | | | | | | | | | | | | | | | | | 2024 | | 2025 | | 2026 | Natural Gas Derivative Contracts: | | | | | | | | | | Fixed price swap contracts: | | | | | | | | | | Average monthly volume (MMBtu) | | | 716,667 | | | 675,000 | | | 291,667 | Weighted-average fixed price | | $ | 3.72 | | $ | 3.74 | | $ | 3.72 | | | | | | | | | | | Collar contracts: | | | | | | | | | | Two-way collars | | | | | | | | | | Average monthly volume (MMBtu) | | | 544,444 | | | 500,000 | | | 291,667 | Weighted-average floor price | | $ | 3.46 | | $ | 3.50 | | $ | 3.50 | Weighted-average ceiling price | | $ | 4.15 | | $ | 4.10 | | $ | 4.10 | | | | | | | | | | | Crude Oil Derivative Contracts: | | | | | | | | | | Fixed price swap contracts: | | | | | | | | | | Average monthly volume (Bbls) | | | 85,889 | | | 53,000 | | | 30,917 | Weighted-average fixed price | | $ | 74.04 | | $ | 70.68 | | $ | 70.68 | | | | | | | | | | | Collar contracts: | | | | | | | | | | Two-way collars | | | | | | | | | | Average monthly volume (Bbls) | | | 102,000 | | | 59,500 | | | — | Weighted-average floor price | | $ | 70.00 | | $ | 70.00 | | $ | — | Weighted-average ceiling price | | $ | 80.20 | | $ | 80.20 | | $ | — | | | | | | | | | | |
Balance Sheet Presentation The following table summarizes both: (i) the netgross fair valuesvalue of commodity derivative instruments by the appropriate balance sheet classification ineven when the Company’s unaudited condensed consolidated balance sheets at September 30, 2017 (in thousands): Type | | Balance Sheet Location (1) | | September 30, 2017 | | Oil swaps | | Derivative financial instruments — current assets | | $ | 49 | | Gas swaps | | Derivative financial instruments — current assets | | 1,006 | | Oil collars | | Derivative financial instruments — current assets | | 969 | | Gas collars | | Derivative financial instruments — current assets | | 872 | | Oil swaps | | Derivative financial instruments — noncurrent liabilities | | (98 | ) | Oil collars | | Derivative financial instruments — noncurrent liabilities | | 6 | | Gas collars | | Derivative financial instruments — noncurrent liabilities | | (186 | ) | Total derivative fair value at period end | | | | $ | 2,618 | |
(1) The fair values of commodity derivative instruments reported in the Company’s unaudited condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation.presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 2024 and December 31, 2023. 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.
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS | | | | | | | | | | | | | | | | | | | Asset | | Liability | | Asset | | Liability | | | | | Derivatives | | Derivatives | | Derivatives | | Derivatives | | | | | March 31, | | March 31, | | December 31, | | December 31, | Type | | Balance Sheet Location | | 2024 | | 2024 | | 2023 | | 2023 | | | | | | (In thousands) | Commodity contracts | | Short-term derivative instruments | | $ | 16,069 | | $ | 11,640 | | $ | 21,657 | | $ | 3,988 | Interest rate swaps | | Short-term derivative instruments | | | — | | | — | | | — | | | — | Gross fair value | | | | | 16,069 | | | 11,640 | | | 21,657 | | | 3,988 | Netting arrangements | | | | | (11,640) | | | (11,640) | | | (3,988) | | | (3,988) | Net recorded fair value | | Short-term derivative instruments | | $ | 4,429 | | $ | — | | $ | 17,669 | | $ | — | | | | | | | | | | | | | | | | Commodity contracts | | Long-term derivative instruments | | $ | 9,237 | | $ | 7,459 | | $ | 17,782 | | $ | 8,377 | Interest rate swaps | | Long-term derivative instruments | | | — | | | — | | | — | | | — | Gross fair value | | | | | 9,237 | | | 7,459 | | | 17,782 | | | 8,377 | Netting arrangements | | | | | (7,459) | | | (7,459) | | | (8,377) | | | (8,377) | Net recorded fair value | | Long-term derivative instruments | | $ | 1,778 | | $ | — | | $ | 9,405 | | $ | — |
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. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands): | | | | | | | | | | | For the Three Months Ended | | | Statements of | December 31, | | | Operations Location | 2024 | | 2023 | Commodity derivative contracts | | Loss (gain) on commodity derivatives | $ | 16,564 | | $ | (15,159) |
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 three months ended March 31, 2024 (in thousands): | | | | Asset retirement obligations at beginning of period | | $ | 123,494 | Liabilities added from acquisition or drilling | | | — | Liabilities settled | | | — | Liabilities removed upon sale of wells | | | — | Accretion expense | | | 2,061 | Revision of estimates | | | — | Asset retirement obligation at end of period | | | 125,555 | Less: Current portion | | | 1,493 | Asset retirement obligations - long-term portion | | $ | 124,062 |
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 7. Long-Term Debt The following table presents the Company’s consolidated debt obligations at the dates indicated: | | | | | | | | | March 31, | | December 31, | | | 2024 | | 2023 | | | | (In thousands) | Revolving Credit Facility (1) | | $ | 115,000 | | $ | 115,000 | Total long-term debt | | $ | 115,000 | | $ | 115,000 |
| (1) | The carrying amount of the Company’s Revolving Credit Facility approximates fair value because the interest rates are variable and reflective of market rates. |
Amended and Restated Credit Agreement On July 31, 2023, OLLC and Amplify Acquisitionco LLC (“Acquisitionco”), as the direct parent of OLLC and wholly owned subsidiary of the Company, entered into the Amended and Restated Credit Agreement, providing for a senior secured reserve-based revolving credit facility. The Revolving Credit Facility is guaranteed by the Company and all of its material subsidiaries and secured by substantially all of its assets. The Revolving Credit Facility matures on July 31, 2027, and is a replacement in full of the prior Revolving Credit Facility by and among OLLC, Acquisitionco, the guarantors party thereto, the lenders party thereto and KeyBank National Association, as the administrative agent (as amended, the “Prior Revolving Credit Facility”). The aggregate principal amount of loans outstanding under the Revolving Credit Facility as of March 31, 2024, was $115.0 million. The borrowing base under the facility is $150.0 million with elected commitments of $135.0 million, and, consistent with the Prior Revolving Credit Facility, the Revolving Credit Facility borrowing base will be subject to redetermination on at least a semi-annual basis, primarily based on a reserve engineering report. Certain key terms and conditions under the Revolving Credit Facility include (but are not limited to): | ● | A maturity date of July 31, 2027; |
| ● | The loans shall bear interest at a rate per annum equal to (i) adjusted SOFR or (ii) an adjusted base rate, plus an applicable margin based on a utilization ratio of the lesser of the borrowing base and the aggregate commitments. The applicable margin ranges from 2.00% to 3.00% for adjusted base rate borrowings, and 3.00% to 4.00% for adjusted SOFR borrowings; |
| ● | The unused commitments under the Revolving Credit Facility will accrue a commitment fee of 0.50%, payable quarterly in arrears; |
| ● | Certain financial covenants, including the maintenance of (i) a net debt leverage ratio not to exceed 3.00 to 1.00, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending and (ii) a current ratio of not less than 1.00 to 1.00, determined as of the last day of each fiscal quarter, in each case commencing with the fiscal quarter ending December 31, 2023; |
| ● | Certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy; and |
| ● | Initial minimum hedging requirements covering 75% of the reasonably projected monthly production of hydrocarbons from proved developed producing reserves for the 24-month period following the effective date of the Revolving Credit Facility (the “First Period”) and (ii) 50% for the 12-month period immediately following the First Period. |
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS As noted above, the Company is required to maintain a minimum current ratio of 1.00 to 1.00, which is measured on the last day of each quarter. On March 31, 2024, the Company’s current ratio was 0.98 to 1.00. On May 2, 2024, the Company received a letter agreement from its lenders waiving any default or event of default as a result of such noncompliance related to the minimum current ratio requirement for the quarter ended March 31, 2024. As a result, the Company was in compliance with all financial covenants as of March 31, 2024. Subsequent event. On May 2, 2024, OLLC completed its spring 2024 borrowing base redetermination, which reaffirmed the borrowing base of $150.0 million with elected commitments of $135.0 million. The next redetermination is expected in the fourth quarter of 2024. 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 | | | | March 31, | | | | 2024 | | 2023 | | Revolving Credit Facility | | 9.37 | % | 9.73 | % |
Letters of Credit At March 31, 2024, the Company had no letters of credit outstanding. Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with the Company’s Revolving Credit Facility were $4.1 million at March 31, 2024. Note 8. Equity Common Stock The Company’s authorized capital stock includes 250,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in the Company’s common stock issued for the three months ended March 31, 2024: | | | |
| Common Stock | Balance, December 31, 2023 | | 39,147,205 | Issuance of common stock | | — | Restricted stock units vested | | 711,728 | Shares withheld for taxes (1) | | (246,903) | Balance, March 31, 2024 | | 39,612,030 |
| (1) | Represents the net settlement on vesting of restricted stock to satisfy tax withholding requirements. |
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 9. Earnings (Loss) 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 | | | March 31, | | | 2024 | | 2023 | Net income (loss) | | $ | (9,396) | | $ | 352,759 | Less: Net income allocated to participating securities | | | — | | | 16,386 | Basic and diluted earnings available to common stockholders | | $ | (9,396) | | $ | 336,373 | | | | | | | | Common shares: | | | | | | | Common shares outstanding — basic | | | 39,410 | | | 38,694 | Dilutive effect of potential common shares | | | — | | | — | Common shares outstanding — diluted | | | 39,410 | | | 38,694 | | | | | | | | Net earnings (loss) per share: | | | | | | | Basic | | $ | (0.24) | | $ | 8.69 | Diluted | | $ | (0.24) | | $ | 8.69 |
Note 10. Long-Term Incentive Plans In May 2021, the shareholders approved a new Equity Incentive Plan (“EIP”) which replaced the Legacy Amplify Management Incentive Plan (the “Legacy Amplify MIP”). As such, no further awards have been granted under the Legacy Amplify MIP. In April 2024, the board of directors of the Company (the “Board”) approved and adopted the Amplify Energy Corp. 2024 Equity Incentive Plan (the “2024 Plan”), subject to stockholder approval at the Company’s Annual Meeting of Stockholders to be held on May 15, 2024. EIP awards are, and, under the Legacy Amplify MIP, were, granted in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance awards, stock awards and other incentive awards. To the extent that an award under the EIP or Legacy Amplify MIP is expired, forfeited or canceled for any reason without having been exercised in full, the unexercised award would then be available again for future grants under the EIP. The EIP is administered by the Board. Restricted Stock Units Restricted Stock Units with Service Vesting Condition Restricted stock units with service vesting conditions (“TSUs”) are accounted for as either equity-classified awards or liability-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 for equity-classified awards are recorded as general and administrative expense. The fair value of liability-classified awards is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general administrative expense and are remeasured at fair value each reporting period. Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The Company granted contingent cash-settlement awards in the form of TSUs (the “Contingent TSUs”) under the EIP in February 2024 that will be settled in shares of stock, subject to stockholder approval of the 2024 Plan. In the event the Company’s stockholders do not approve the 2024 Plan, the Contingent TSUs will be settled in cash pursuant to the terms of the applicable award agreement. The Contingent TSUs are accounted for as liability-classified awards and vest in substantially equal installments over a three-year period. The unrecognized cost associated with the TSUs was $7.8 million at March 31, 2024. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted average period of approximately 2.3 years. Of the unrecognized share-based compensation expense for TSUs, $4.1 million relates to liability-classified awards and will be subsequently remeasured at each reporting period. The Company recognized $0.3 million in liability-classified share-based compensation expense at March 31, 2024 for the Contingent TSUs. The following table summarizes information regarding the TSUs activity for the period presented: | | | | | | | | | | Weighted- | | | | | Average Grant- | | | Number of | | Date Fair Value | | | Units | | per Unit (1) | TSUs outstanding at December 31, 2023 | | 1,331,456 | | $ | 5.77 | Granted (2) | | 709,402 | | $ | 6.09 | Forfeited | | (5,922) | | $ | 5.04 | Vested | | (604,684) | | $ | 4.95 | TSUs outstanding at March 31, 2024 (3) | | 1,430,252 | | $ | 6.28 |
| (1) | Determined by dividing the aggregate grant-date fair value of awards by the number of awards issued. |
| (2) | The aggregate grant-date fair value of TSUs issued for the three months ended March 31, 2024 was $4.3 million based on a grant-date market price of $6.09 per share. |
| (3) | As of March 31, 2024, 709,402 of the unvested TSUs were accounted for as liability awards in “accrued liabilities” in the Unaudited Condensed Consolidated Balance sheet. |
Restricted Stock Units with Market and Service Vesting Conditions Restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as either equity-classified or liability-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. The fair value of the awards is estimated on their grant dates using a Monte Carlo simulation. The Company recognizes compensation cost over the requisite service or performance period. The Company accounts for forfeitures as they occur. Vesting of PSUs can range from zero to 200% of the target awards granted based on the Company’s relative total shareholder return as compared to the total shareholder return of the Company’s performance peer group over the applicable performance period. The 2022 and 2023 PSU awards are accounted for as equity-classified awards and were issued with a three-year vesting period beginning on the grant date and ending on the third anniversary of the grant date. The three-year performance period for the 2022 awards is January 1, 2022 through December 31, 2024. The three-year performance period for the 2023 awards is January 1, 2023 through December 31, 2025. The Company granted contingent cash-settlement awards in the form of PSUs (the “Contingent PSUs”) in February 2024 that will be settled in shares of stock, subject to stockholder approval of the 2024 Plan. In the event the Company’s stockholders do not approve the 2024 Plan, the Contingent PSUs will be settled in cash pursuant to the terms of the applicable award agreement. The Contingent PSUs are accounted for as liability-classified awards and were issued with a three-year vesting period beginning on the grant date and ending on the third anniversary of the grant date. The three-year performance period for the Contingent PSUs is January 1, 2024 through December 31, 2026. Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Compensation costs related to the awards are recorded as general and administrative expense. The unrecognized cost associated with these awards was $4.3 million at March 31, 2024. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.3 years. Of the unrecognized share-based compensation expense, $2.3 million relates to liability-classified awards and will be subsequently remeasured at each reporting period. The Company recognized $0.2 million in liability-classified share-based compensation expense at March 31, 2024 for the Contingent PSUs. The below table reflects the ranges for the assumptions used in the Monte Carlo model for the Contingent PSU awards: | | | | | | February 2024 | | Expected volatility | | 75.8 | % | Dividend yield | | 0.00 | % | Risk-free interest rate | | 4.19 | % |
The following table summarizes information regarding the PSUs activity for the period presented: | | | | | | | | | | Weighted- | | | | | Average Grant- | | | Number of | | Date Fair Value | | | Units | | per Unit (1) | PSUs outstanding at December 31, 2023 | | 402,701 | | $ | 9.31 | Granted (2) | | 312,843 | | $ | 8.28 | Forfeited | | — | | $ | — | Vested | | (107,044) | | $ | 2.63 | PSUs outstanding at March 31, 2024 (3) | | 608,500 | | $ | 9.95 |
| (1) | Determined by dividing the aggregate grant-date fair value of awards by the number of awards issued. |
| (2) | The aggregate grant-date fair value of PSUs issued for the three months ended March 31, 2024 was $2.6 million based on a calculated fair value price ranging from $2.63 to $9.18 per share. |
| (3) | As of March 31, 2024, 269,897 of the unvested PSUs were accounted for as liability awards in “accrued liabilities” in the Unaudited Condensed Consolidated Balance sheet. |
Compensation Expense The following table summarizes the location and fair value amountsamount of all commodity derivative instrumentsrecognized compensation expense associated with the EIP, which are reflected in the unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets at September 30, 2017 (in thousands): | | | | September 30, 2017 | | Not Designated as | | | | Gross Recognized | | Gross Amounts | | Net Recognized
Fair Value | | ASC 815 Hedges | | Balance Sheet Location Classification | | Assets/Liabilities | | Offset | | Assets/Liabilities | | Derivative Assets: | | | | | | | | | | Commodity contracts | | Derivative financial instruments — current | | $ | 5,858 | | $ | (2,962 | ) | $ | 2,896 | | Commodity contracts | | Derivative financial instruments — noncurrent | | 1,032 | | (1,032 | ) | — | | | | | | $ | 6,890 | | $ | (3,994 | ) | $ | 2,896 | | Derivative Liabilities: | | | | | | | | | | Commodity contracts | | Derivative financial instruments — current | | $ | (2,962 | ) | $ | 2,962 | | $ | — | | Commodity contracts | | Derivative financial instruments — noncurrent | | (1,310 | ) | 1,032 | | (278 | ) | | | | | $ | (4,272 | ) | $ | 3,994 | | $ | (278 | ) |
Asaccompanying Unaudited Condensed Consolidated Statements of December 31, 2016, the Company did not have any open commodity derivative contract positions.
Gains/Losses on Commodity Derivative Contracts
The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in “Gains (losses) on commodity derivative contracts—net” within revenues in the unaudited condensed consolidated statements of operations.
The following table presents net cash received for commodity derivative contracts and unrealized net gains recorded by the Company related to the change in fair value of the derivative instruments in “Gains (losses) on commodity derivative contracts—net”Operations for the periods presented (in thousands):
| | For the Three Months Ended | | For the Nine Months Ended | | | | September 30, 2017 | | September 30, 2017 | | Net cash received for commodity derivative contracts | | $ | 2,909 | | $ | 6,149 | | Unrealized net (losses) gains | | (6,500 | ) | 2,618 | | Gains (losses) on commodity derivative contracts—net | | $ | (3,591 | ) | $ | 8,767 | |
| | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | Share-based compensation costs | | | | | | | Share-based compensation - equity awards | | $ | 1,120 | | $ | 941 | Share-based compensation - liability awards | | | 411 | | | — | | | $ | 1,531 | | $ | 941 |
Cash settlements, as presented
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 11. Leases The Company has leases for office space, warehouse space and equipment in the table above, represent realized gains related to the Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair value changes on its derivative instruments in each reporting period. The changes in fair value result from new positionscorporate office and settlements that may occur during each reporting period,operating regions as well as vehicles, compressors and surface rentals related to its business operations. In addition, the relationships between contract pricesCompany has right-of-way leases to operate the San Pedro Bay Pipeline. 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 leases can be terminated with 30-day prior written notice. The majority of its month-to-month leases are not included as a lease liability in its balance sheet because continuation of the lease is not reasonably certain. Additionally, the Company elected the short-term practical expedient to exclude leases with a term of twelve months or less. For the quarter ended March 31, 2024, all of the Company’s leases qualified as operating leases, and it did not have any existing or new leases qualifying as financing leases or variable leases. The Company’s corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, the Company uses an 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 associated forward curves.
5. Property and Equipment
Property and equipment consisted of the following as of the dates presented:
| | September 30, 2017 | | December 31, 2016 | | | | (in thousands) | | Oil and gas properties, on the basis of full-cost accounting: | | | | | | Proved properties | | $ | 709,647 | | $ | 573,150 | | Unproved properties | | 26,178 | | 65,080 | | Other property and equipment | | 6,543 | | 6,339 | | Less accumulated depreciation, depletion and amortization | | (59,349 | ) | (12,974 | ) | Net property and equipment | | $ | 683,019 | | $ | 631,595 | |
Oil and Gas Properties
current economic environment. The Company capitalizes internal costs directly related to explorationuses a reasonable market interest rate for its office equipment and development activities to oil and gas properties. During the three and nine months ended September 30, 2017 and 2016, the Company capitalized the following (in thousands):vehicle leases. | | Successor | | | Predecessor | | Successor | | | Predecessor | | | | Three Months
Ended | | | Three Months
Ended | | Nine Months
Ended | | | Nine Months
Ended | | | | September 30, 2017 | | | September 30, 2016 | | September 30, 2017 | | | September 30, 2016 | | Internal costs capitalized to oil and gas properties (1) | | $ | 1,651 | | | $ | 1,049 | | $ | 4,656 | | | $ | 3,311 | | | | | | | | | | | | | | | | | |
(1) Inclusive of $0.8 million and $0.1 million of qualifying share-based compensation expense forFor the three months ended September 30, 2017March 31, 2024 and 2016, respectively. For2023, the nine months ended September 30, 2017 and 2016, inclusive of $2.0Company recognized approximately $0.5 million and $0.5 million, respectively, of qualifying share-based compensation expense.costs relating to the operating leases in the Unaudited Condensed Consolidated Statements of Operations.
The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds realized from the sale or disposition of oil and gas properties are accounted for as a reductionSupplemental cash flow information related to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or losslease liabilities is generally recognized in income. During the nine months ended September 30, 2017, the Company disposed of certain oil and gas equipment for cash proceeds of $1.4 million, which were reflected as a reduction of oil and gas properties with no gain or loss recognized. During the three months ended September 30, 2017, the Company closed on the sale of certain oil and gas properties in Lincoln County, Oklahoma, for $7.0 million in cash ($2.9 million, net after assumption of liabilities), subject to standard post-closing adjustments. The net proceeds from the sale were retained for general corporate purposes.
The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of the Company’s oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying unaudited condensed consolidated statements of operations.table below:
| | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | | | | (In thousands) | Non-cash amounts included in the measurement of lease liabilities: | | | | | | | Operating cash flows from operating leases | | $ | 349 | | $ | 288 |
The Company did not record an impairment of oil and gas properties during the three or nine months ended September 30, 2017. The three and nine month periods ended September 30, 2016 included impairments of oil and gas properties of $33.9 million and $224.6 million, respectively. These impairments were primarily the result of continued low commodity prices, which resulted in a decrease in the discounted present value of the Company’s proved oil and natural gas reserves.
DD&A is calculated using the Units of Production Method (“UOP���). The UOP calculation multiplies the percentage of total estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A and impairment, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties for the three and nine months ended September 30, 2017 and 2016, respectively:
| | Successor | | | Predecessor | | Successor | | | Predecessor | | Successor | | | Predecessor | | Successor | | | Predecessor | | | | Three Months Ended
September 30, | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Nine Months Ended
September 30, | | | 2017 | | | 2016 | | 2017 | | | 2016 | | 2017 | | | 2016 | | 2017 | | | 2016 | | | | (in thousands) | | (per Boe) | | (in thousands) | | (per Boe) | | Depletion expense | | $ | 14,575 | | | $ | 15,231 | | $ | 7.42 | | | $ | 5.90 | | $ | 44,695 | | | $ | 57,018 | | $ | 7.29 | | | $ | 6.92 | | Depreciation on other property and equipment | | 595 | | | 525 | | 0.30 | | | 0.20 | | 1,776 | | | 2,211 | | 0.29 | | | 0.27 | | Depreciation, depletion, and amortization | | $ | 15,170 | | | $ | 15,756 | | $ | 7.72 | | | $ | 6.10 | | $ | 46,471 | | | $ | 59,229 | | $ | 7.58 | | | $ | 7.19 | |
Oil and gas unproved properties include costs that are not being depleted or amortized. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties and become part of our depletion base and subject to the full cost ceiling limitation. No impairment of unproved properties was recorded during the three or nine months ended September 30, 2017. Unproved property was $26.2 million and $65.1 million at September 30, 2017 and December 31, 2016, respectively.
Other Property and Equipment
Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is calculated principally using the straight-line method over the estimated useful lives of the assets, which range from five to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.
6. Other Noncurrent Assets
The following table presents the components of other noncurrent assets as of the dates presented: | | September 30, 2017 | | December 31, 2016 | | | | (in thousands) | | Deferred financing costs associated with the Exit Facility | | $ | 1,286 | | $ | 1,187 | | Field equipment inventory | | 4,221 | | 2,619 | | Other | | 1,649 | | 1,649 | | Other noncurrent assets | | $ | 7,156 | | $ | 5,455 | |
7. Accrued Liabilities
The following table presents the components of accrued liabilities as of the dates presented:
| | September 30, 2017 | | December 31, 2016 | | | | (in thousands) | | Accrued oil and gas capital expenditures | | $ | 12,281 | | $ | 6,118 | | Accrued revenue and royalty distributions | | 17,707 | | 28,262 | | Accrued lease operating and workover expense | | 6,200 | | 8,932 | | Accrued interest | | 123 | | 254 | | Accrued taxes | | 2,980 | | 2,537 | | Compensation and benefit related accruals | | 5,133 | | 3,516 | | Other | | 2,563 | | 4,112 | | Accrued liabilities | | $ | 46,987 | | $ | 53,731 | |
8. Asset Retirement Obligations
Asset Retirement Obligations (“AROs”) represent the estimated future abandonment costs of tangible assets, such as wells, serviceCompany’s right-of-use assets and other facilities. The estimated fair valuelease liabilities for the period presented:
| | | | | | | | | March 31, | | December 31, | | | 2024 | | 2023 | | | | (In thousands) | Right-of-use asset | | $ | 5,407 | | $ | 5,756 | | | | | | | | Lease liabilities: | | | | | | | Current lease liability | | | 1,740 | | | 1,737 | Long-term lease liability | | | 4,704 | | | 5,090 | Total lease liability | | $ | 6,444 | | $ | 6,827 |
The following table reflects the changesCompany’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 | 2024 | | $ | 1,066 | | $ | 568 | | $ | 1,634 | 2025 | | | 1,421 | | | 573 | | | 1,994 | 2026 | | | 1,200 | | | 87 | | | 1,287 | 2027 | | | 832 | | | 4 | | | 836 | 2028 and thereafter | | | 1,790 | | | — | | | 1,790 | Total lease payments | | | 6,309 | | | 1,232 | | | 7,541 | Less: interest | | | 1,014 | | | 83 | | | 1,097 | Present value of lease liabilities | | $ | 5,295 | | $ | 1,149 | | $ | 6,444 |
The weighted average remaining lease terms and discount rate for all of the Company’s AROsoperating leases for the period presented: | | | | | | | | March 31, | | | | 2024 | | 2023 | | Weighted average remaining lease term (years): | | | | | | Office and warehouse space | | 4.17 | | 4.60 | | Vehicles | | 0.36 | | 0.37 | | Office equipment | | 0.01 | | 0.03 | | Weighted average discount rate: | | | | | | Office and warehouse space | | 5.30 | % | 4.90 | % | Vehicles | | 1.19 | % | 1.33 | % | Office equipment | | 0.06 | % | 0.10 | % |
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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): | | | | | | | | | March 31, | | December 31, | | | 2024 | | 2023 | Accrued lease operating expense | | $ | 11,440 | | $ | 14,239 | Accrued liability - pipeline incident | | | 2,670 | | | 9,331 | Accrued liability - current portion of pipeline incident settlement | | | 2,000 | | | 2,000 | Accrued capital expenditures | | | 6,500 | | | 8,019 | Accrued general and administrative expense | | | 2,159 | | | 5,335 | Accrued production and ad valorem tax | | | 3,659 | | | 3,502 | Accrued commitment fee and other expense | | | 2,478 | | | 2,626 | Operating lease liability | | | 1,740 | | | 1,737 | Asset retirement obligations | | | 1,493 | | | 1,493 | Accrued current income tax payable | | | 1,395 | | | — | Accrued interest payable | | | 284 | | | 1,792 | Other | | | 958 | | | 797 | Accrued liabilities | | $ | 36,776 | | $ | 50,871 |
Accounts Receivable Accounts receivable consisted of the following at the dates indicated (in thousands): | | | | | | | | | March 31, | | December 31, | | | 2024 | | 2023 | Oil and natural gas receivables | | $ | 31,570 | | $ | 31,131 | Insurance receivable - pipeline incident | | | 1,437 | | | 3,571 | Joint interest owners and other | | | 5,207 | | | 6,042 | Total accounts receivable | | | 38,214 | | | 40,744 | Less: allowance for doubtful accounts | | | (1,674) | | | (1,648) | Total accounts receivable, net | | $ | 36,540 | | $ | 39,096 |
Supplemental Cash Flows Supplemental cash flows for the periods presented (in thousands): | | Successor | | | Predecessor | | | | Nine Months
Ended | | | Nine Months
Ended | | | | September 30, 2017 | | | September 30, 2016 | | Asset retirement obligations — beginning of period | | $ | 14,200 | | | $ | 18,708 | | Liabilities incurred | | 259 | | | 520 | | Revisions | | — | | | — | | Liabilities settled | | (107 | ) | | (278 | ) | Liabilities eliminated through asset sales | | (1,146 | ) | | — | | Current period accretion expense | | 833 | | | 1,316 | | Asset retirement obligations — end of period | | $ | 14,039 | | | $ | 20,266 | |
| | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | Supplemental cash flows: | | | | | | | Cash paid for interest, net of amounts capitalized | | $ | 3,920 | | $ | 4,502 | | | | | | | | Noncash investing and financing activities: | | | | | | | Increase (decrease) in capital expenditures in payables and accrued liabilities | | | (1,520) | | | 1,966 |
9. Debt
Table of Contents AMPLIFY ENERGY CORP. Exit FacilityNOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 13. Related Party Transactions Related Party Agreements At September 30, 2017 and December 31, 2016,There have been no transactions between the Company maintainedand any related person in which the related person had a reserves based credit facility with a borrowing base of $170.0 million (the “Exit Facility”). At September 30, 2017, and December 31, 2016, the Company had $128.1 million drawn on the Exit Facility and had outstanding letters of credit obligations totaling $1.9 million. As of September 30, 2017, the Company had $40.0 million of availability on the Exit Facility.
The Exit Facility bearsdirect or indirect material interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. Forfor the three months ended September 30, 2017,March 31, 2024 and 2023.
Note 14. Commitments and Contingencies Litigation and Environmental As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although the weighted average interest rate was 5.7%. Unamortized debt issuanceCompany 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. Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of $1.3 millionfuture expenditures for environmental remediation are not discounted to their present value, unless the amount and $1.2 million associated withtiming of the Exit Facilityexpenditures are included in “Other noncurrent assets” on the unaudited condensed consolidated balance sheets at September 30, 2017,fixed or reliably determinable. At March 31, 2024 and December 31, 2016, respectively.2023, the Company had no environmental reserves recorded in its Unaudited Condensed Consolidated Balance Sheet. Beta Pipeline Incident Please refer to “Note 16. Beta Pipeline Incident” for details. Sinking Fund Trust Agreement Beta Operating Company, LLC (“Beta LLC”), a wholly owned subsidiary, assumed an obligation with a third party to make payments into a sinking fund in connection with the Company’s 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. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of March 31, 2024, the account balance included in restricted investments was approximately $4.5 million. Supplemental Bond for Decommissioning Liabilities Trust Agreement Beta LLC has a decommissioning obligation with BOEM in connection with the Company’s properties in federal waters offshore Southern California. The Company supports its decommissioning obligation with $161.3 million of A-rated surety bonds. In addition to interest expense, the Exit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter. On May 24, 2017,December 2021, the Company entered into two escrow funding agreements with its surety providers to fund interest-bearing escrow accounts on a quarterly basis to reimburse and indemnify the First Amendmentsurety providers for any claims arising under the surety bonds related to the Exit Facility (the “First Amendment”). The First Amendment, among other items, (i) moveddecommissioning of our Beta LLC properties. In March 2024, the first scheduled borrowing base redetermination from April 2018Company amended one of the escrow funding agreements to October 2017; (ii) removed the requirement to maintain a cash collateral account with the administrative agent indecrease the amount of $40.0 million; (iii) removedfunded from $14.8 million per year to $8.0 million per year. There were no changes made to the requirement to maintain at least 20% liquiditysecond escrow agreement. The obligation for these agreements ceases when the total aggregate value of the then effective borrowing base; (iv) amendedescrow accounts reaches $172.6 million.
Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The below table outlines the required mortgage threshold from 95% to 90%; (v) amended the threshold amountupdated funding commitment for which the borrower is required to provide advance notice to the administrative agent of a sale or disposition of oil and gas properties which occurs during the period between two successive redeterminations of the borrowing base; (vi) amended the required ratio of total net indebtedness to EBITDA from 2.25:1.00 to 4.00:1.00; (vii) amended the required EBITDA to interest coverage ratio from not less than 3.00:1.00 to not less than 2.50:1.00; and (viii) removed certain limitations on capital expenditures.these agreements at March 31, 2024 (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | Payment Due by Period | Funding commitment | | Total | | Remaining 2024 | | 2025 | | 2026 | | 2027 | | 2028 | | Thereafter | Federal escrow fund payments | | $ | 145,550 | | $ | 6,000 | | $ | 8,000 | | $ | 8,000 | | $ | 8,000 | | $ | 8,000 | | $ | 107,550 | State escrow fund payments | | | 10,079 | | | 775 | | | 1,034 | | | 1,034 | | | 1,034 | | | 1,034 | | | 5,168 | Total sinking fund payments | | $ | 155,629 | | $ | 6,775 | | $ | 9,034 | | $ | 9,034 | | $ | 9,034 | | $ | 9,034 | | $ | 112,718 |
As of September 30, 2017,March 31, 2024, the Company has funded $17.6 million into the escrow accounts which is reflected in “Restricted investments” on the Unaudited Condensed Consolidated Balance Sheet. Note 15. Income Taxes The Company’s current income tax expense was $1.4 million and $12.5 million for the three months ended March 31, 2024 and 2023, respectively. The Company’s deferred income tax benefit was $4.7 million and $259.5 million for the three months ended March 31, 2024 and 2023, respectively. The effective tax rates for the three months ended March 31, 2024 and 2023 were 26.0% and (233.4%), respectively. The item that had the most significant impact on the difference between the statutory U.S. federal income tax rate of 21% and the effective tax rate for the three months ended March 31, 2024 was the weighted state accrual rate. The items that had the most significant impact on the difference between the statutory U.S. federal income tax rate of 21% and the effective tax rate for the three months ended March 31, 2023 was the release of the valuation allowances. Net deferred tax assets relate to net operating loss carryforwards, interest expense carryforwards, tax credits, and other temporary differences expected to produce tax deductions in compliance withfuture periods. The realization of these assets depends on recognition of sufficient future taxable income in specific federal and state tax jurisdictions in which those temporary differences are deductible. In assessing the need for a valuation allowance on its debt covenants.deferred tax assets, the Company considers whether it is more likely than not that all of its deferred tax assets will be realized. On December 31, 2023, the Company release all of its valuation allowance of $284.9 million, which increased net deferred tax assets as of such date. Note 16. Beta Pipeline Incident On October 27, 2017,2, 2021, contractors operating under the direction of Beta LLC observed an oil sheen on the water approximately four miles off the coast of Newport Beach, California. Beta LLC platform personnel were notified and promptly initiated the Company’s borrowing baseOil Spill Response Plan. On October 3, 2021, a Unified Command, consisting of the Company, the U.S. Coast Guard and California Department of Fish and Wildlife’s Office of Spill Prevention and Response, was redeterminedestablished to respond to the Incident. Reports from the Unified Command’s contracted commercial divers and Remotely Operated Vehicle footage indicated that a 4,000-foot section of the Company’s pipeline had been displaced and that the pipeline had a 13-inch split, running parallel to the pipe, releasing approximately 588 barrels of oil. All operations were suspended and the pipeline was shut-in pending the Company’s receipt of the required regulatory approvals to restart operations, including but not limited to, approval of a written restart plan from the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), Office of Pipeline Safety. On April 10, 2023, the Company announced that it received the required approvals from federal regulatory agencies to restart operations at the existing amountBeta Field. Since such date, the pipeline has been operated in accordance with the restart procedures that were reviewed and approved by PHMSA. On December 15, 2021, a federal grand jury in the Central District of California returned a federal criminal indictment against the Company, Beta LLC, and San Pedro Bay Pipeline Company in connection with the Incident. As previously disclosed, state authorities were conducting parallel criminal investigations. The Company’s Anadarko Basin assets in Texas and Oklahoma were excludedCompany reached court-approved agreements to resolve all criminal matters stemming from the redeterminationIncident. As part of the borrowing base. Theresolution with the United States, the Company believes the carrying amountagreed to plead guilty to one count of misdemeanor negligent discharge of oil in violation of the Exit Facility at September 30, 2017 approximates its fair value (Level 2) dueClean Water Act, and, agreed to the variable naturepay a fine of the Exit Facility interest rate.
10. Equity and Share-Based Compensation
Common Shares
Share Activity
The following table summarizes changesapproximately $7.1 million in the number of outstanding shares during the nine months ended September 30, 2017:
| | Common
Stock | | Treasury
Stock(1) | | Share count as of December 31, 2016 | | 24,994,867 | | — | | Common stock issued | | 103,967 | | — | | Acquisition of treasury stock | | — | | (33,409 | ) | Share count as of September 30, 2017 | | 25,098,834 | | (33,409 | ) |
(1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.
Share-Based Compensation
2016 Long Term Incentive Plan
On the Effective Date, the Company established the 2016 LTIP and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees, directors and certain other persons (the “Award Shares”). The types of awards that may be granted under the 2016 LTIP include stock options, restricted stock units, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock of the reorganized Company, as well as certain cash-based awards (the “Awards”). The terms of each award are as determined by the Compensation Committee of the Board of Directors. Awards that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future issuance under the 2016 LTIP. At September 30, 2017, 2,299,088 Award Shares remain available for issuance under the terms of the 2016 LTIP.
Restricted Stock Units
At September 30, 2017, the Company had 494,794 non-vested restricted stock units outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. Restricted stock units granted to employees under the 2016 LTIP vest ratablyinstallments over a period of three years: one-sixth will vest on the six-month anniversaryyears, serve a term of four years’ probation and reimburse governmental agencies approximately $5.8 million for their response to this event. Additionally, as part of the grant date, an additional one-sixth will vest onresolution with the twelve-month anniversarystate of California, the grant date, an additional one-third will vest onCompany agreed to enter a plea of No Contest to six misdemeanor charges, and, as a result, paid a fine in the twenty-four month anniversaryamount of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Restricted stock units granted to non-employee directors vest on the first to occur of (i) December 31, 2017, (ii) the date the non-employee director ceases$4.9 million to be distributed among the state of California, including the State’s Fish and Game Preservation Fund, and Orange County, agreed to serve a directorone-year term of the Board (other than for cause), (iii) the director’s death, (iv) the director’s disability or (v) a change in control of the Company.
The fair value of restricted stock units was based on grant date fair value of the Company’s common stock. Compensation expense is recognized ratably over the requisite service period.
The following table summarizes the Company’s non-vested restricted stock unit award activity for the nine months ended September 30, 2017:
| | Restricted Stock | | Weighted Average
Grant Date
Fair Value | | Non-vested shares outstanding at December 31, 2016 | | 685,662 | | $ | 19.66 | | Granted | | 17,500 | | $ | 18.62 | | Vested | | (103,967 | ) | $ | 19.66 | | Forfeited | | (104,401 | ) | $ | 19.66 | | Non-vested shares outstanding at September 30, 2017 | | 494,794 | | $ | 19.63 | |
Unrecognized expense as of September 30, 2017, for all outstanding restricted stock units under the 2016 LTIP was $3.9 millionprobation and will be recognized over a weighted average period of 1.2 years. Subsequentagreed to September 30, 2017, 174,135 restricted stock units vested before consideration of minimum statutory tax withholding requirements.
On August 22, 2017, the Company amended the employment agreement of Fredric F. Brace, former President and Chief Executive Officer (the “Executive Employment Amendment”). Among other provisions, the Executive Employment Amendment accelerated the vesting of all outstanding equity awards of Mr. Bracecertain compliance enhancements to October 21, 2017. As a result, approximately $0.8 million of compensation expense associated with Mr. Brace’s non-vested restricted stock was accelerated into the three and nine months ended September 30, 2017.
Stock Options
At September 30, 2017, the Company had 423,438 non-vested stock options outstanding pursuant to the 2016 LTIP. Stock Option Awards granted under the 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date.
its operations. The Company utilizesis currently subject to a number of ongoing investigations related to the Black-Scholes-Merton option pricing modelIncident by certain federal and state agencies and may be subject to determinenew investigations and proceedings in the fair valuefuture, the results of stock option awards. Determiningwhich may have a material impact on the fair valueCompany’s business and results of equity-based awards requires judgment, including estimatingoperations and could put pressure on its liquidity position going forward. With respect to PHMSA’s investigation, on April 6, 2023, PHMSA provided the expected term that stock option awards will be outstanding priorCompany notice of PHMSA’s positions regarding “probable violations of the Pipeline Safety Regulations” in connection with the Incident. The Company has responded to exercisethe notice and is conferring with PHMSA regarding a resolution. Amplify continues to comply with all regulatory requirements and investigations. The outcomes of these investigations and the associated volatility. The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the nine months ended September 30, 2017:
| | Options | | Range of Exercise
Prices | | Weighted
Average
Exercise Price | | Weighted
Average
Remaining
Contractual
Term (Years) | | Stock options outstanding at December 31, 2016 | | 627,806 | | | | $ | 19.66 | | 9.1 | | Granted | | 4,000 | | $ | 19.08 | | $ | 19.08 | | 9.5 | | Vested | | (103,967 | ) | $ | 19.08-20.97 | | $ | 19.66 | | — | | Forfeited | | (104,401 | ) | $ | 19.66 | | $ | 19.66 | | — | | Stock options outstanding at September 30, 2017 | | 423,438 | | | | $ | 19.66 | | 9.1 | | Vested and exercisable at end of period(1) | | 103,967 | | $ | 19.08-20.97 | | $ | 19.66 | | 9.1 | |
(1) Vested and exercisable options at September 30, 2017, had no aggregate intrinsic value.
Unrecognized expense asnature of September 30, 2017, for all outstanding stock options under the 2016 LTIP was $1.9 million andany remedies pursued will be recognized over a weighted average period of 1.3 years. Subsequent to September 30, 2017, 171,885 stock options vested before consideration of minimum statutory tax withholding requirements.
On August 22, 2017, the Company amended the Executive Employment Amendment. Among other provisions, the Executive Employment Amendment accelerated the vesting of all outstanding equity awards of Mr. Brace to October 21, 2017. As a result, approximately $0.4 million of compensation expense associated with Mr. Brace’s non-vested stock options was accelerated into the three and nine months ended September 30, 2017.
Non-Employee Director Restricted Stock Units Containing a Market Condition
On November 23, 2016, the Company issued certain restricted stock units to non-employee directors that contain a market vesting condition. These restricted stock units will vest (i)depend on the first business day following the date on which the trailing 60-day average share price (including any dividends paid) of the Company’s common stock is equal to or greater than $30.00 or (ii) upon a change in control of the Company. Additionally, all unvested restricted stock units containing a market vesting condition will be immediately forfeited upon the first to occur of (i) the fifth (5th) anniversary of the grant date or (ii) any participant’s termination as a director for any reason (except for a termination as part of a change in control of the Company).
These restricted stock awards are accounted for as liability awards under FASB ASC 718 as the awards allow for the withholding of taxes at the discretion of the non-employee director. relevant authorities and may result in regulatory or other enforcement actions, as well as civil liability.
The liability is re-measured,Company, Beta LLC, and San Pedro Bay Pipeline Company were named as defendants in a consolidated putative class action in the United States District Court for the Central District of California, asserting claims against the Company, Beta LLC, San Pedro Bay Pipeline Company, among others. On August 25, 2022, the Company reached an agreement in principle with a corresponding adjustmentplaintiffs in the class action to earnings, at each fiscal quarter-end duringresolve all civil claims against it and its subsidiaries. The settlement of $50.0 million, which also includes certain injunctive relief, has been and will continue to be funded under the performance cycle.Company’s insurance policies. The liability and related compensation expense of these awards for each period is recognized by dividing the fair valueCourt granted final approval of the total liability bysettlement on April 24, 2023. Separately, on March 1, 2023, the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is riskCompany announced that the recorded compensation may not accurately reflectvessels that struck and damaged the amount ultimately earned by the non-employee directors. The restricted stock unit awards issuedpipeline and their respective owners and operators agreed to non-employee directors containing a market condition has a derived service period of one year. At September 30, 2017,pay the Company recorded$96.5 million in a $0.7 million liability included within “Accrued liabilities” in the unaudited condensed consolidated balance sheetssettlement. This settlement resolved Amplify’s affirmative claims related to the market condition awards. The fair valueIncident, and as such, Amplify dismissed its legal claims against those parties.
Under the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq. (“OPA 90”), the Company’s pipeline was designated by the U.S. Coast Guard as the source of the restricted stock containingoil 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 market condition was $11.05 per unit at September 30, 2017. Asjoint assessment of September 30, 2017, unrecognized stock-based compensationsuch 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 market condition awards was $0.1 million and will be recognized over a weighted-average period of 0.1 years.
11. Income Taxes
For the nine months ended September 30, 2017,such assessment are difficult to project. While the Company recorded no income tax expense or benefit. The significant difference between our effective tax rate and the federal statutory income tax rate of 35% is primarily dueanticipates insurance will reimburse it for expenses related to the effectNatural Resource Damage Assessment, any potentially uncovered expenses may be material and could impact the Company’s business and results of changesoperations and could put pressure on its liquidity position going forward.
Based on presently enacted laws and regulations and currently available facts, the Company estimates that the total costs it has incurred or will incur with respect to the Incident to be approximately $190.0 million to $210.0 million. The range of total costs is based on the Company’s assumptions regarding (i) settlement of costs associated with certain vendors for response and remediation expenses, (ii) resolution of certain third-party claims, excluding claims with respect to losses, which are not probable or reasonably estimable, and (iii) future claims and lawsuits. While the Company believes it has accurately reflected all probable and reasonably estimable costs incurred in the Company’s valuation allowance. DuringUnaudited Consolidated Statements of Operations, these estimates are subject to uncertainties associated with the nineunderlying assumptions. Accordingly, as the Company’s assumptions and estimates may change in future periods based on future events, the Company can provide no assurance that total costs will not materially change in future periods. Table of Contents AMPLIFY ENERGY CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The Company’s estimates do not include (i) the nature, extent and cost of future legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Incident, (ii) any lost revenue associated with the suspension of operations at Beta, (iii) any liabilities or costs, including regulatory costs, that are not reasonably estimable at this time or that relate to contingencies where the Company currently regards the likelihood of loss as being only reasonably possible or remote and (iv) the costs associated with the permanent repair of the pipeline and the restart of operations at Beta. In accordance with customary insurance practice, the Company maintains insurance policies, including loss of production insurance, against many potential losses or liabilities arising from its operations, which, in addition to the settlement amount disclosed, have covered a material portion of aggregate costs associated with the Incident. However, the Company can provide no assurance that its coverage will continue to 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. On March 31, 2024, and December 31, 2023, the Company’s insurance receivables were $1.4 million and $3.6 million, respectively. Excluding the costs associated with the resolution of the federal and state matters discussed above, for the three months ended September 30, 2017,March 31, 2024, the Company incurred response and remediation expenses and legal fees of $0.7 million, which primarily relates to certain legal costs that are not expected to be recovered under an insurance policy and are classified as “Pipeline Incident Loss” on the Company’s valuation allowance decreased by $13.0 million fromUnaudited Condensed Consolidated Statements of Operations. For more information, please see our annual report on Form 10-K for the year ended December 31, 2016, bringing2023 filed with the total valuation allowance to $147.8 million at September 30, 2017. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets are realizable. The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.
12. Earnings (Loss) Per Share
Successor
The following table provides a reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted earnings per share for the Successor Periods presented:
| | Three Months Ended | | Nine Months Ended | | | | September 30, 2017 | | September 30, 2017 | | | | (in thousands, except per
share amounts) | | (in thousands, except per
share amounts) | | Net Earnings: | | | | | | Net income | | $ | 3,663 | | $ | 35,890 | | Participating securities—non-vested restricted stock | | (82 | ) | (932 | ) | Basic and diluted earnings | | $ | 3,581 | | $ | 34,958 | | | | | | | | Common Shares: | | | | | | Common shares outstanding — basic (1) | | 25,116 | | 25,074 | | Dilutive effect of potential common shares | | — | | — | | Common shares outstanding — diluted | | 25,116 | | 25,074 | | | | | | | | Net Earnings Per Share: | | | | | | Basic | | $ | 0.14 | | $ | 1.39 | | Diluted | | $ | 0.14 | | $ | 1.39 | | Antidilutive stock options (2) | | 424 | | 526 | | Antidilutive warrants (3) | | 6,626 | | 6,626 | |
(1) Weighted-average common shares outstanding for basic and diluted earnings per share purposes includes 17,533 shares of common stock that, while not issued and outstanding at September 30, 2017, are required by the Plan to be issued.
(2) Amount represents stock options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.
(3) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.SEC on March 7, 2024.
Predecessor
The Company’s nonvested stock awards, which were granted as part of the 2012 LTIP, contained nonforfeitable rights to dividends and as such, were considered to be participating securities and are included in the computation of basic and diluted earnings per share, pursuant to the two-class method.
The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net earnings (loss) per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented below.
The following table provides a reconciliation of net loss to preferred shareholders, common shareholders, and participating securities for purposes of computing net loss per share for the Predecessor Periods presented:
| | Three Months Ended | | Nine Months Ended | | | | September 30, 2016 | | September 30, 2016 | | | | (in thousands, except per
share amounts) | | (in thousands, except per
share amounts) | | Net loss | | $ | (38,384 | ) | $ | (208,696 | ) | Preferred Dividend | | — | | — | | Participating securities—non-vested restricted stock | | — | | — | | Net loss attributable to shareholders | | $ | (38,384 | ) | $ | (208,696 | ) | | | | | | | Weighted average shares outstanding | | 10,657 | | 10,644 | | Basic and diluted net loss per share | | $ | (3.60 | ) | $ | (19.61 | ) |
13. Related Party TransactionsNote 17. Subsequent Events
Borrowing Base Redetermination The Company has entered into an arrangement with EcoStim Energy Solutions, Inc. (“EcoStim”)See Note 7 for well stimulation and completion services. EcoStim is an affiliate of Fir Tree Inc., an entity holding approximately 25.5% of the Company’s outstanding common stock. For the three and nine months ended September 30, 2017, the Company paid approximately $5.9 million and $7.3 million, respectively, to EcoStim for services provided. No transactions with EcoStim occurred during the three and nine months ended September 30, 2016.
14. Commitments and Contingencies
The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices.
The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of loss can be reasonably estimated, it accrues a liability for the contingent obligation. As newadditional information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changesrelating to the Company’s accruals could have a material effect on its resultsborrowing base redetermination.
Table of operations. As of September 30, 2017, and December 31, 2016, the Company’s total accrual for all loss contingencies was $1.4 million and $1.1 million, respectively.Contents During the nine months ended September 30, 2017, the Company received an insurance reimbursement in the amount of $1.9 million, which was reflected as a reduction of “Lease operating and workover” expenses in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2017.
15. Subsequent Event
On October 25, 2017, David J. Sambrooks was appointed to the position of President and Chief Executive Officer, effective immediately upon the resignation of Mr. Brace on November 1, 2017. The Board of Directors of the Company (the “Board”) also approved an increase in the number of directors, from seven directors to eight directors, and Mr. Sambrooks was appointed to the Board, effective concurrently with his appointment as an executive officer.
In connection with the appointment of Mr. Sambrooks as President and Chief Executive Officer, Mr. Sambrooks and the Company entered into an employment agreement outlining the terms of his employment as President and Chief Executive Officer of the Company. Among other provisions, Mr. Sambrooks received incentive awards including (i) the grant of 67,889 time-vested restricted stock units and (ii) the grant of 135,778 performance stock units (“PSUs”). The time-vested restricted stock units will generally vest in three installments: 1/3 will vest on the one-year anniversary of the award date, an additional 1/3 will vest on the two-year anniversary of the award date and the final 1/3 will vest on the three-year anniversary of the award date. The PSUs will vest, if at all, based upon the performance of the Company’s stock during the period of October 25, 2017 through October 31, 2020 (the “Performance Period”). Half of the PSUs will vest, if at all, based upon the Company’s total absolute stockholder return for the Performance Period, and the other half will vest, if at all, based upon the Company’s relative total stockholder return when measuring the Company’s stock performance during the Performance Period to the stock performance of a selected peer group during the Performance Period.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OPERATIONS. The following discussionManagement’s Discussion and analysisAnalysis of our financial conditionFinancial Condition and resultsResults of operationsOperations should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2016, and the related management’s discussion and analysis contained in our Annual Report on Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 30, 2017, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Quarterly Report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this report and in the Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.
Forward-looking statements may include statements about our:
· business strategy, including our business strategy post-emergence from our Chapter 11 Cases;
· estimated future net reserves and present value thereof;
· technology;
· financial condition, revenues, cash flows and expenses;
· levels of indebtedness, liquidity, borrowing capacity and compliance with debt covenants;
· financial strategy, budget, projections and operating results;
· oil and natural gas realized prices;
· timing and amount of future production of oil and natural gas;
· availability of drilling and production equipment;
· the amount, nature and timing of capital expenditures, including future development costs;
· availability of oilfield labor;
· availability of third party natural gas gathering and processing capacity;
· availability and terms of capital;
· drilling of wells, including our identified drilling locations;
· successful results from our identified drilling locations;
· marketing of oil and natural gas;
· the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cash position and levels of indebtedness;
· infrastructure for salt water disposal and electricity;
· current and future ability to dispose of salt water;
· sources of electricity utilized in operations and the related infrastructures;
· costs of developing our properties and conducting other operations;
· general economic conditions;
· effectiveness of our risk management activities;
· environmental liabilities;
· counterparty credit risk;
· the outcome of pending and future litigation;
· governmental regulation and taxation of the oil and natural gas industry;
· developments in oil and natural gas producing countries;
· new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting;
· uncertainty regarding our future operating results; and
· plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.
Overview
We are an independent exploration and production company focused on the application of modern drilling and completion techniques in oil and liquids-rich basins in the onshore United States. Our operations are primarily focused on exploration and production activities in the Mississippian Lime and Anadarko Basin. The terms “Company,” “we,” “us,” “our,” and similar terms refer to us and our subsidiary, unless the context indicates otherwise.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we realize from the sale of that production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, if any, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
Upon our emergence from the Chapter 11 Cases on October 21, 2016, we adopted fresh start accounting as required by US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, our consolidated financial statements on or after October 21, 2016, are not comparable with our consolidated financial statements prior to that date. References to “Successor Period” relate to the results of operations for the period January 1, 2017 through September 30, 2017 and references to “Predecessor Period” refer to the results of operations of the Company from January 1, 2016 through September 30, 2016.
Operations Update
Mississippian Lime
For the three months ended September 30, 2017 and June 30, 2017, our average daily production from the Mississippian Lime asset was as follows:
| | Three Months Ended
September 30, 2017 | | Three Months Ended
June 30, 2017 | | Increase/(Decrease)
in Production | | | | | | | | | | Average daily production: | | | | | | | | Oil (Bbls) | | 4,940 | | 4,938 | | — | % | Natural gas liquids (Bbls) | | 4,145 | | 4,466 | | (7.2 | )% | Natural gas (Mcf) | | 51,130 | | 53,246 | | (4.0 | )% | Net Boe/day | | 17,606 | | 18,278 | | (3.7 | )% |
The following table shows our total number of horizontal wells spud and brought into production in the Mississippian Lime asset during the third quarter of 2017:
| | Total Number of
Gross Horizontal
Wells Spud (1) | | Total Number of
Gross Horizontal
Wells Brought
into Production | | Mississippian Lime | | 10 | | 9 | |
(1) We had two rigs drilling in the Mississippian Lime horizontal well program at September 30, 2017. Of the ten wells spud, three were producing, five were awaiting completion and two were being drilled at quarter-end.
In the third quarter of 2017, we incurred approximately $39.8 million of operational capital expenditures in the Mississippian Lime basin.
Anadarko Basin
For the three months ended September 30, 2017 and June 30, 2017, our average daily production from our Anadarko Basin asset was as follows:
| | Three Months Ended
September 30, 2017 | | Three Months Ended
June 30, 2017 | | Decrease in
Production | | | | | | | | | | Average daily production: | | | | | | | | Oil (Bbls) | | 1,329 | | 1,475 | | (9.9 | )% | Natural gas liquids (Bbls) | | 992 | | 1,115 | | (11.0 | )% | Natural gas (Mcf) | | 8,581 | | 9,735 | | (11.9 | )% | Net Boe/day | | 3,752 | | 4,212 | | (10.9 | )% |
We did not spud any wells in our Anadarko Basin asset and did not have any operated drilling rigs in the area during the third quarter of 2017.
Capital Expenditures
During the three and nine months ended September 30, 2017, we incurred operational capital expenditures of $40.1 million and $97.7 million, respectively, which consisted of the following:
| | For the Three
Months Ended
September 30, 2017 | | For the Nine
Months Ended
September 30, 2017 | | Drilling and completion activities | | $ | 36,269 | | $ | 89,975 | | Acquisition of acreage and seismic data | | 3,845 | | 7,748 | | Operational capital expenditures incurred | | $ | 40,114 | | $ | 97,723 | | Capitalized G&A, office, ARO & other | | 1,856 | | 5,512 | | Capitalized interest | | 408 | | 2,054 | | Total capital expenditures incurred | | $ | 42,378 | | $ | 105,289 | |
Operational capital expenditures by area were as follows:
| | For the Three
Months Ended
September 30, 2017 | | For the Nine
Months Ended
September 30, 2017 | | Mississippian Lime | | $ | 39,800 | | $ | 95,490 | | Anadarko Basin | | 314 | | 2,233 | | Total operational capital expenditures incurred | | $ | 40,114 | | $ | 97,723 | |
We are currently operating two drilling rigs in the Mississippian Lime asset. Based upon a two rig program, we would expect to invest between $130.0 million to $140.0 million of capital for exploration, development and lease and seismic acquisition, and drill 36 to 40 gross wells during the year ended December 31, 2017.
Factors that Significantly Affect Our Risk
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost and terms of such capital, our current financial condition, expectations regarding the future price for oil and natural gas, and operational considerations.
The volumes of oil and natural gas that we produce are driven by several factors, including:
· success in the drilling of new wells, including exploratory wells, and the recompletion or workover of existing wells;
· the amount of capital we invest in the leasing and development of our oil and natural gas properties;
· facility or equipment availability and unexpected downtime;
· delays imposed by or resulting from compliance with regulatory requirements;
· the rate at which production volumes on our wells naturally decline; and
· our ability to economically dispose of salt water produced in conjunction with our production of oil and gas.
We follow the full cost method of accounting for our oil and gas properties. For the three and nine months ended September 30, 2017, the results of our full cost “ceiling test” did not require us to recognize impairments of our oil and gas properties. While impairments do not impact cash flow from operating activities or liquidity, they do decrease our net income and shareholders’ equity.
We dispose of large volumes of saltwater produced in conjunction with crude oil and natural gas from drilling and production operations in the Mississippian Lime. Our disposal operations are conducted pursuant to permits issued to us by governmental authorities overseeing such disposal activities.
There is a continuing concern and regulatory scrutiny surrounding any potential correlation between the injection of saltwater into disposal wells and those activities alleged contribution to increased seismic activity in certain areas, including the areas in which we operate, Oklahoma and Texas. On February 16, 2016, the Oil and Gas Conservation Division (“OGCD”) of the Oklahoma Corporation Commission (“OCC”) requested we curtail our wastewater disposal volumes into the Arbuckle formation in our Mississippian Lime assets by approximately 40%. On March 7, 2016 and August 19, 2016, the OGCD identified additional wells that were required to reduce disposal volume. The OGCD established caps for additional wells on February 24, 2017. On March 1, 2017, the OGCD also issued a statement saying that further actions to reduce the earthquake rate in Oklahoma could be expected. Our current plans are for future disposal wells to inject into formations other than the Arbuckle and we are currently disposing of approximately 40% of our produced salt water into formations other than the Arbuckle. We have timely met and satisfied all requests of the OCC regarding changes and/or reductions in disposal capacity in our operated Arbuckle disposal wells, and now inject at a rate which is approximately 20% below the OGCD’s prescribed limits for the Arbuckle formation without adverse impact to our production base. We are currently in compliance with the OGCD’s latest requests regarding Arbuckle injection limits; however a change in disposal well regulations or injection limits, or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations and/or reduce the volume of oil and natural gas that we produce from our wells.
Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are 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. Our customary practice is at each fiscal year end our technical team meets with representatives of our independent reserves engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. We maintain an internal staff of petroleum engineers, land and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data utilized in the reserves estimation process. The primary inputs to the reserves estimation process are comprised of technical information, financial data, ownership interests and production data. The valuation of our proved reserves is sensitive to changes in these inputs and, as a result, minor updates to these inputs can result in significant changes in the valuation of such reserves. The extent of any such changes in reserves valuation is inherently uncertain until the final completion of the proved reserves estimates at each fiscal year end.
Results of Operations
The following tables summarize our revenues for the three and nine months ended September 30, 2017 and 2016 (in thousands):
| | Three Months Ended September 30, | | | | Crude Oil | | Natural Gas | | NGLs | | Total | | 2016 Revenues (Predecessor) | | $ | 35,584 | | $ | 17,676 | | $ | 8,939 | | $ | 62,199 | | Changes due to volumes | | (11,820 | ) | (3,776 | ) | (2,649 | ) | (18,245 | ) | Changes due to price | | 3,426 | | 70 | | 4,366 | | 7,862 | | 2017 Revenues (Successor) | | $ | 27,190 | | $ | 13,970 | | $ | 10,656 | | $ | 51,816 | |
| | Nine Months Ended September 30, | | | | Crude Oil | | Natural Gas | | NGLs | | Total | | 2016 Revenues (Predecessor) | | $ | 104,832 | | $ | 44,486 | | $ | 25,073 | | $ | 174,391 | | Changes due to volumes | | (48,583 | ) | (12,776 | ) | (6,717 | ) | (68,076 | ) | Changes due to price | | 29,248 | | 14,611 | | 13,224 | | 57,083 | | 2017 Revenues (Successor) | | $ | 85,497 | | $ | 46,321 | | $ | 31,580 | | $ | 163,398 | |
Oil, NGL and Natural Gas Pricing
The following table sets forth information regarding average realized sales prices for the periods indicated:
| | Successor | | | Predecessor | | | | Successor | | | Predecessor | | | | | | For the Three | | | For the Three | | | | For the Nine | | | For the Nine | | | | | | Months Ended | | | Months Ended | | | | Months Ended | | | Months Ended | | | | | | September 30,
2017 | | | September 30,
2016 | | %
Change | | September 30,
2017 | | | September 30,
2016 | | %
Change | | AVERAGE SALES PRICES: | | | | | | | | | | | | | | | | Oil, without realized derivatives (per Bbl) | | $ | 47.14 | | | $ | 43.00 | | 9.6 | % | $ | 47.83 | | | $ | 37.42 | | 27.8 | % | Oil, with realized derivatives (per Bbl) | | $ | 50.11 | | | $ | 43.00 | | 16.5 | % | $ | 50.09 | | | $ | 37.42 | | 33.9 | % | Natural gas liquids, without realized derivatives (per Bbl) | | $ | 22.55 | | | $ | 15.15 | | 48.8 | % | $ | 21.17 | | | $ | 13.86 | | 52.7 | % | Natural gas liquids, with realized derivatives (per Bbl) | | $ | 22.55 | | | $ | 15.15 | | 48.8 | % | $ | 21.17 | | | $ | 13.86 | | 52.7 | % | Natural gas, without realized derivatives (per Mcf) | | $ | 2.54 | | | $ | 2.53 | | 0.4 | % | $ | 2.71 | | | $ | 2.04 | | 32.8 | % | Natural gas, with realized derivatives (per Mcf) | | $ | 2.76 | | | $ | 2.53 | | 9.1 | % | $ | 2.83 | | | $ | 2.04 | | 38.7 | % |
Oil Revenues
Successor Period
Our oil sales revenues for the three and nine months ended September 30, 2017 were $27.2 million and $85.5 million, respectively. Our oil sales revenues were comprised of $21.6 million and $67.8 million, respectively, from our Mississippian Lime assets and $5.6 million and $17.7 million, respectively, from our Anadarko Basin assets.
Predecessor Period
Our oil sales revenues for the three and nine months ended September 30, 2016 were $35.6 million and $104.8 million, respectively. Our oil sales revenue was comprised of $29.0 million and $85.2 million, respectively, from our Mississippian Lime assets and $6.6 million and $19.6 million, respectively, from our Anadarko Basin assets.
Natural Gas Revenues
Successor Period
Our natural gas sales revenues for the three and nine months ended September 30, 2017 were $14.0 million and $46.3 million, respectively. Our natural gas sales revenues were comprised of $12.1 million and $40.0 million, respectively, from our Mississippian Lime assets and $1.9 million and $6.3 million, respectively, from our Anadarko Basin assets.
Predecessor Period
Our natural gas sales revenues for the three and nine months ended September 30, 2016 were $17.7 million and $44.5 million, respectively. Our natural gas sales revenue was comprised of $15.5 million and $39.3 million, respectively, from our Mississippian Lime assets and $2.2 million and $5.2 million, respectively, from our Anadarko Basin assets.
NGL Revenues
Successor Period
Our NGLs sales revenues for the three and nine months ended September 30, 2017 were $10.7 million and $31.6 million, respectively. Our NGLs sales revenues were comprised of $8.5 million and $25.4 million, respectively, from our Mississippian Lime assets and $2.2 million and $6.2 million, respectively, from our Anadarko Basin assets.
Predecessor Period
Our NGLs sales revenues for the three and nine months ended September 30, 2016 were $8.9 million and $25.1 million, respectively. Our NGLs sales revenue was comprised of $7.3 million and $20.5 million, respectively, from our Mississippian Lime assets and $1.6 million and $4.6 million, respectively, from our Anadarko Basin assets.
Gains (losses) on Commodity Derivative Contracts—Net
A summary of our open commodity derivative positions is included the financial statements in “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Condensed Consolidated Financial Statements — Note 4. Risk Management and Derivative Instruments” of this report. The following tables provide financial information associated with our oil and natural gas hedges for the period indicated (in thousands):
| | For the Three
Months Ended
September 30, 2017 | | For the Nine
Months Ended
September 30, 2017 | | Cash settlements: | | | | | | Oil derivatives | | $ | 1,713 | | $ | 4,041 | | Natural gas derivatives | | 1,196 | | 2,108 | | Total cash settlements | | $ | 2,909 | | $ | 6,149 | | | | | | | | Gains (losses) due to fair value changes: | | | | | | Oil derivatives | | $ | (5,618 | ) | $ | 925 | | Natural gas derivatives | | (882 | ) | 1,693 | | Total gains (losses) on fair value changes | | $ | (6,500 | ) | $ | 2,618 | | | | | | | | Gains (losses) on commodity derivative contracts—net | | $ | (3,591 | ) | $ | 8,767 | |
Successor Period
During the three and nine months ended September 30, 2017, we had unrealized gains (losses) of $(6.5) million and $2.6 million from our mark-to-market derivative positions, representing the changesaccompanying notes in fair value from new positions and settlements that occurred during the period, as well as the relationship between contract prices and the associated forward curves. Cash receipts from the settlements of derivatives during the three and nine months ended September 30, 2017 were $2.9 million and $6.1 million, respectively.
Predecessor Period
We had no open or settled commodity derivative positions during the three and nine months ended September 30, 2016.
Oil, Natural Gas and NGL Production
| | Successor | | | Predecessor | | | | Successor | | | Predecessor | | | | | | For the Three
Months Ended | | | For the Three
Months Ended | | | | For the Nine
Months Ended | | | For the Nine
Months Ended | | | | | | September
30, 2017 | | | September
30, 2016 | | %
Change | | September
30, 2017 | | | September
30, 2016 | | %
Change | | PRODUCTION DATA: | | | | | | | | | | | | | | | | Oil (Bbls/d) | | | | | | | | | | | | | | | | Mississippian Lime | | 4,940 | | | 7,266 | | (32.0 | )% | 5,158 | | | 8,279 | | (37.7 | )% | Anadarko Basin | | 1,329 | | | 1,728 | | (23.1 | )% | 1,389 | | | 1,947 | | (28.7 | )% | Natural gas liquids (Bbls/d) | | | | | | | | | | | | | | | | Mississippian Lime | | 4,145 | | | 5,209 | | (20.4 | )% | 4,398 | | | 5,350 | | (17.8 | )% | Anadarko Basin | | 992 | | | 1,204 | | (17.6 | )% | 1,066 | | | 1,250 | | (14.7 | )% | Natural gas (Mcf/d) | | | | | | | | | | | | | | | | Mississippian Lime | | 51,130 | | | 65,287 | | (21.7 | )% | 53,474 | | | 68,612 | | (22.1 | )% | Anadarko Basin | | 8,581 | | | 10,624 | | (19.2 | )% | 9,225 | | | 10,872 | | (15.1 | )% | Combined (Boe/d) | | | | | | | | | | | | | | | | Mississippian Lime | | 17,606 | | | 23,357 | | (24.6 | )% | 18,469 | | | 25,065 | | (26.3 | )% | Anadarko Basin | | 3,752 | | | 4,702 | | (20.2 | )% | 3,993 | | | 5,008 | | (20.3 | )% |
Commodity production for the three and nine months ended September 30, 2017 is lower compared to the three and nine months ended September 30, 2016 due to natural decline and a lower level of drilling activity during the 2017 period.
Expenses
| | Successor | | | Predecessor | | Successor | | | Predecessor | | Successor | | | Predecessor | | Successor | | | Predecessor | | | | Three Months Ended
September 30, | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Nine Months Ended
September 30, | | | | 2017 | | | 2016 | | 2017 | | | 2016 | | 2017 | | | 2016 | | 2017 | | | 2016 | | | | (in thousands) | | (per Boe) | | (in thousands) | | (per Boe) | | EXPENSES: | | | | | | | | | | | | | | | | | | | | | | Lease operating and workover | | $ | 15,653 | | | $ | 17,650 | | $ | 7.97 | | | $ | 6.84 | | $ | 48,064 | | | $ | 49,520 | | $ | 7.84 | | | $ | 6.01 | | Gathering and transportation | | 3,699 | | | 4,296 | | 1.88 | | | 1.66 | | 11,027 | | | 13,428 | | 1.80 | | | 1.63 | | Severance and other taxes | | 2,352 | | | 1,788 | | 1.20 | | | 0.69 | | 6,168 | | | 4,776 | | 1.01 | | | 0.58 | | Asset retirement accretion | | 274 | | | 452 | | 0.14 | | | 0.17 | | 833 | | | 1,316 | | 0.14 | | | 0.16 | | Depreciation, depletion, and amortization | | 15,170 | | | 15,756 | | 7.72 | | | 6.10 | | 46,471 | | | 59,229 | | 7.58 | | | 7.19 | | Impairment of oil and gas properties | | — | | | 33,887 | | — | | | 13.13 | | — | | | 224,584 | | — | | | 27.26 | | General and administrative | | 7,255 | | | 3,308 | | 3.69 | | | 1.27 | | 23,102 | | | 19,093 | | 3.77 | | | 2.32 | | Debt restructuring costs and advisory fees | | — | | | — | | — | | | — | | — | | | 7,589 | | — | | | 0.92 | | Total expenses | | $ | 44,403 | | | $ | 77,137 | | $ | 22.60 | | | $ | 29.86 | | $ | 135,665 | | | $ | 379,535 | | $ | 22.14 | | | $ | 46.07 | |
Lease Operating and Workover
Successor Period
Our lease operating and workover expenses for the three and nine months ended September 30, 2017 were $15.7 million and $48.1 million, respectively. Lease operating and workover expenses were $7.97 and $7.84 per Boe, respectively. As previously discussed in “Part I. Financial Information — Item“Item 1. Financial Statements — Notes to the Unaudited Condensed Consolidated Financial Statements — Note 14. CommitmentsStatements” contained herein and Contingencies”, lease operating and workover expenses were positively impacted during the nine months ended September 30, 2017 by a $1.9 million reimbursement received for an insurance claim.
Predecessor Period
Our lease operating and workover expenses for the three and nine months ended September 30, 2016 were $17.7 million and $49.5 million, respectively. Lease operating and workover expenses were $6.84 and $6.01 per Boe, respectively.
Gathering and Transportation
Successor Period
Our gathering and transportation expenses for the three and nine months ended September 30, 2017 were $3.7 million and $11.0 million, respectively. Gathering and transportation expenses were $1.88 and $1.80 per Boe, respectively.
Predecessor Period
Our gathering and transportation expenses for the three and nine months ended September 30, 2016 were $4.3 million and $13.4 million, respectively. Gathering and transportation expenses were $1.66 and $1.63 per Boe, respectively.
Severance and Other Taxes
| | Successor | | | Predecessor | | Successor | | | Predecessor | | | | Three Months Ended | | | Three Months Ended | | Nine Months Ended | | | Nine Months Ended | | | | September 30, 2017 | | | September 30, 2016 | | September 30, 2017 | | | September 30, 2016 | | | | (in thousands) | | | (in thousands) | | (in thousands) | | | (in thousands) | | Total oil, natural gas, and natural gas liquids sales | | $ | 51,816 | | | $ | 62,199 | | $ | 163,398 | | | $ | 174,391 | | | | | | | | | | | | | | Severance taxes | | 2,128 | | | 1,353 | | 5,496 | | | 3,717 | | Ad valorem and other taxes | | 224 | | | 435 | | 672 | | | 1,059 | | Severance and other taxes | | $ | 2,352 | | | $ | 1,788 | | $ | 6,168 | | | $ | 4,776 | | Severance taxes as a percentage of sales | | 4.1 | % | | 2.2 | % | 3.4 | % | | 2.1 | % | Severance and other taxes as a percentage of sales | | 4.5 | % | | 2.9 | % | 3.8 | % | | 2.7 | % |
Successor Period
Our severance and other tax expenses for the three and nine months ended September 30, 2017 were $2.4 million or 4.5%in “Item 1A. Risk Factors” of sales and $6.2 million or 3.8% of sales, respectively. Severance tax for the three and nine months ended September 30, 2017 was $2.1 million or 4.1% of sales and $5.5 million or 3.4% of sales, respectively.
Prior to July 1, 2017, the State of Oklahoma had a crude oil and natural gas production tax incentive for wells that commenced production between July 1, 2011 and July 1, 2015, which allowed for a 1.0% production tax rate for the first 48 months of production. In May 2017, new legislation was signed into law in Oklahoma that increased the incentive tax rate from 1.0% to 4.0% on those wells. After the 48 month incentive period ends, the tax rate on such wells increases to 7.0%. The new 4.0% tax rate on these wells went into effect on July 1, 2017 and caused our average production tax rate to trend higher in the three months ended September 30, 2017. While the impact of increased production taxes is uncertain, based upon our current production, we estimate the elimination of these tax incentive wells will increase monthly production taxes by approximately $0.2 million.
Predecessor Period
Our severance and other tax expenses for the three and nine months ended September 30, 2016 were $1.8 million or 2.9% of sales and $4.8 million or 2.7% of sales, respectively. Severance tax for the three and nine months ended September 30, 2016 was $1.4 million or 2.2% of sales and $3.7 million or 2.1% of sales, respectively.
Depreciation, Depletion and Amortization (“DD&A”)
Successor Period
Our DD&A expenses for the three and nine months ended September 30, 2017 were $15.2 million at a cost of $7.72 per Boe and $46.5 million at a cost of $7.58 per Boe, respectively.
Predecessor Period
Our DD&A expenses for the three and nine months ended September 30, 2016 were $15.8 million at a cost of $6.10 per Boe and $59.2 million at a cost of $7.19 per Boe, respectively.
Impairment of Oil and Gas Properties
Successor Period
We did not incur any impairments of oil and gas properties during the three or nine months ended September 30, 2017.
Predecessor Period
Our impairment of oil and gas properties for the three and nine months ended September 30, 2016 was $33.9 million and $224.6 million, respectively. The impairment expense recognized in the Predecessor Period was primarily due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of continued low commodity prices, which are a significant input into the calculation of the discounted future cash flows associated with our proved oil and gas reserves.
General and Administrative (“G&A”)
Successor Period
Our G&A expense for the three and nine months ended September 30, 2017 was $7.3 million at a cost of $3.69 per Boe and $23.1 million at a cost of $3.77 per Boe, respectively. G&A for the three and nine months ended September 30, 2017 was impacted by non-cash stock based compensation expense for awards issued pursuant to the 2016 LTIP of $2.8 million and $7.1 million, respectively, as well as trailing costs incurred related to the Chapter 11 Cases of $0.1 million and $2.7 million, respectively.
Predecessor Period
Our G&A expense for the three and nine months ended September 30, 2016 was $3.3 million at a cost of $1.27 per Boe and $19.1 million at a cost of $2.32 per Boe, respectively. G&A for the nine months ended September 30, 2016 included the acceleration of rent and related expenses associated with the Houston office lease abandonment totaling $2.5 million.
Debt Restructuring Costs and Advisory Fees
Successor Period
We did not incur any debt restructuring costs or advisory fees during the three or nine months ended September 30, 2017. Trailing costs associated with the Chapter 11 Cases incurred subsequent to the Emergence Date are included in G&A expense, as discussed above.
Predecessor Period
For the nine months ended September 30, 2016 we incurred $7.6 million of advisory fees to assist with analyzing various strategic alternatives to address our liquidity and capital structure. Costs associated with the Chapter 11 Cases incurred subsequent to April 30, 2016 were included in reorganization items, net, as discussed below.
Other Expense
| | Successor | | | Predecessor | | Successor | | | Predecessor | | | | For the Three
Months Ended | | | For the Three
Months Ended | | For the Nine
Months Ended | | | For the Nine
Months Ended | | | | September 30, 2017 | | | September 30, 2016 | | September 30, 2017 | | | September 30, 2016 | | | | (in thousands) | | | (in thousands) | | (in thousands) | | | (in thousands) | | OTHER EXPENSE | | | | | | | | | | | | Interest income | | $ | — | | | $ | — | | $ | — | | | $ | 81 | | Interest expense | | (1,949 | ) | | (2,668 | ) | (5,630 | ) | | (73,965 | ) | Amortization of deferred financing costs | | (108 | ) | | — | | (277 | ) | | — | | Amortization of deferred gain | | — | | | — | | — | | | 8,246 | | Capitalized interest | | 408 | | | — | | 2,053 | | | — | | Interest expense—net of amounts capitalized | | (1,649 | ) | | (2,668 | ) | (3,854 | ) | | (65,719 | ) | Reorganization items, net | | — | | | (22,772 | ) | — | | | 57,764 | | | | | | | | | | | | | | Total other expense | | $ | (1,649 | ) | | $ | (25,440 | ) | $ | (3,854 | ) | | $ | (7,874 | ) |
Interest Expense
Successor Period
Interest expense for the three and nine months ended September 30, 2017 was $1.9 million and $5.6 million, respectively. Interest expense related to our Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. For the three months ended September 30, 2017, the weighted average interest rate was 5.7%. We also capitalized $0.4 million and $2.1 million, respectively, of interest expense to our unproved oil and gas properties during the three and nine months ended September 30, 2017.
Predecessor Period
Our interest expense for the three and nine months ended September 30, 2016 was $2.7 million and $74.0 million, respectively. During the three and nine months ended September 30, 2016, interest expense ceased for all debt except amounts outstanding under the credit facility beginning at the petition date of April 30, 2016. During the nine months ended September 30, 2016, interest expense was offset by $8.2 million related to the amortization of the deferred gain on extinguished debt. No interest expense was capitalized for the three and nine months ended September 30, 2016, due to the transfer of all balances related to unproved properties to the full cost pool at December 31, 2015.
Provision for Income Taxes
Successor Period
We recorded no income tax expense or benefit due to the change in our valuation allowance recorded against our net deferred tax assets. Our valuation allowance decreased by $13.0 million from December 31, 2016 bringing our total valuation allowance to $147.8 million at September 30, 2017.
Predecessor Period
We recorded no income tax expense or benefit. During the nine months ended September 30, 2016, we recorded $70.9 million in additional valuation allowance, bringing the total valuation allowance to $766.0 million at September 30, 2016.
Reorganization Items, Net
Successor Period
We did not incur any reorganization items during the three or nine months ended September 30, 2017.
Predecessor Period
We recognized a net loss of $(22.8) million and a net gain of $57.8 million in reorganization items, net during the three and nine months ended September 30, 2016, respectively. Reorganization items, net represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated.
Liquidity and Capital Resources
Overview
The following table presents a summary of our key financial indicators at the dates presented (in thousands):
| | September 30, 2017 | | December 31, 2016 | | Cash and cash equivalents | | $ | 76,548 | | $ | 76,838 | | Net working capital | | 58,397 | | 67,637 | | Total long-term debt | | 128,059 | | 128,059 | | Total stockholders’ equity | | 605,597 | | 561,814 | | Available borrowing capacity | | 40,000 | | — | | | | | | | | | |
Our decisions regarding capital structure, hedging and drilling are based upon many factors, including anticipated future commodity pricing, expected economic conditions and recoverable reserves.
We anticipate our operating cash flows and cash on hand will be our primary sources of liquidity although we may seek to supplement our liquidity through divestitures, additional borrowings or debt or equity securities offerings as circumstances and market conditions dictate. We believe the combination of these sources of liquidity will be adequate to fund anticipated capital expenditures, service our existing debt and remain compliant with all other contractual commitments.
Our cash flows from operations are impacted by various factors, the most significant of which is the market pricing for oil, NGLs and natural gas. The pricing for these commodities is volatile, and the factors that impact such market pricing are global and therefore outside of our control. As a result, it is not possible for us to precisely predict our future cash flows from operating revenues due to these market forces.
We enter into hedging activities with respect to a portion of our production to manage our exposure to oil, NGLs and natural gas price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.
Consistent with our comprehensive growth strategy of focusing on a portfolio of core assets capable of supporting a long-term, sustainable drilling program, we are actively considering more substantial divestitures and other asset monetization transactions with respect to assets that we do not believe meet our strategic objectives. These transactions may involve significant asset positions, entire business units or corporate level transactions. Depending upon the success, timing and structure of any such transactions, the amount of proceeds we receive from portfolio management activity could materially increase during the remainder of 2017. In conjunction with our consideration of more substantial divestitures, we are also considering substantial acquisitions or other business combinations that further our comprehensive growth strategy.
Significant Sources of Capital
Exit Facility
At September 30, 2017, in addition to cash on hand of $76.5 million, we maintained the Exit Facility. The Exit Facility has a current borrowing base of $170.0 million. At September 30, 2017, we had $128.1 million drawn on the Exit Facility and outstanding letters of credit obligations totaling $1.9 million. As of September 30, 2017, we had $40.0 million of availability on the Exit Facility.
The Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. For the three months ended September 30, 2017, the weighted average interest rate was 5.7%.
In addition to interest expense, the Exit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter.
On May 24, 2017, we entered into the First Amendment to the Exit Facility. The First Amendment, among other items, (i) moved the first scheduled borrowing base redetermination from April 2018 to October 2017; (ii) removed the requirement to maintain a cash collateral account with the administrative agent in the amount of $40.0 million; (iii) removed the requirement to maintain at least 20% liquidity of the then effective borrowing base; (iv) amended the required mortgage threshold from 95% to 90%; (v) amended the threshold amount for which the borrower is required to provide advance notice to the administrative agent of a sale or disposition of oil and gas properties which occurs during the period between two successive redeterminations of the borrowing base; (vi) amended the required ratio of total net indebtedness to EBITDA from 2.25:1.00 to 4.00:1.00; (vii) amended the required EBITDA to interest coverage ratio from not less than 3.00:1.00 to not less than 2.50:1.00; and (viii) removed certain limitations on capital expenditures.
As of September 30, 2017, we were in compliance with our debt covenants.
On October 27, 2017, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. Our Anadarko Basin assets in Texas and Oklahoma were excluded from the redetermination of the borrowing base.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our condensed consolidated cash flows from operating, investing and financing activities for the periods presented. For information regarding the individual components of our cash flow amounts, please refer to the unaudited condensed consolidated statements of cash flows included under “Part I. Financial Information — Item 1. Financial Statements”of this Quarterly Report.
Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Part I. Financial Information — Item 3. Quantitative and Qualitative Disclosures about Market Risk.”
The following information highlights the significant period-to-period variances in our cash flow amounts (in thousands):
| | Successor | | | Predecessor | | | | For the Nine Months
Ended September 30, 2017 | | | For the Nine Months
Ended September 30, 2016 | | Net cash provided by operating activities | | $ | 89,317 | | | $ | 78,244 | | Net cash used in investing activities | | (88,606 | ) | | (129,072 | ) | Net cash (used in) provided by financing activities | | (1,001 | ) | | 249,331 | | Net change in cash | | $ | (290 | ) | | $ | 198,503 | |
Cash flows provided by operating activities
Net cash provided by operating activities was $89.3 million and $78.2 million for the nine months ended September 30, 2017 and 2016, respectively.
Cash flows used in investing activities
We had net cash used in investing activities of $88.6 million and $129.1 million for the nine months ended September 30, 2017 and 2016, respectively. Net cash used in investing activities for the Successor Period and Predecessor Period primarily represents cash invested in oil and gas property and equipment.
Cash flows (used in) provided by financing activities
We had net cash used in financing activities for the nine months ended September 30, 2017, of $1.0 million and net cash provided by financing activities for the nine months ended September 30, 2016, of $249.3 million. Net cash used in financing activity for the Successor Period relates to deferred financing costs and the acquisition of treasury stock. Net cash provided by financing activities for the Predecessor Period primarily represents borrowings from the revolving credit facility of $249.4 million.
Critical Accounting Policies and Estimates
A discussion of our critical accounting policies and estimates is included in our Annual Report on the Form 10-K for the year ended December 31, 2016. There2023 (“2023 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 located in Oklahoma, the Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana and the Eagle Ford (non-op). Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. Industry Trends 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; conflicts in the Middle East; global inventories of oil and natural gas and the uncertainty associated with recovering oil demand; inflation and future monetary policy; and governmental policies aimed at transitioning towards lower carbon energy. Due to these factors, among others, we expect prices for some or all commodities to remain volatile. Thus, we cannot predict with reasonable certainty the extent to which these factors may impact our business, results of operations, financial condition and cash flows. Recent Developments Borrowing Base Redetermination On May 2, 2024, OLLC completed its spring 2024 borrowing base redetermination, which reaffirmed the borrowing base of $150.0 million with elected commitments of $135.0 million. The next redetermination is expected in the fourth quarter of 2024. 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 been no material changeshad, or are reasonably likely to those policies. 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 2023 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 unaudited condensed 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 unaudited condensed consolidated financial position, results of operations and cash flows. Results of Operations Other Items
Obligations and Commitments
We have various contractual obligations for operating leases, including drilling contracts, as well as lease commitments and commitments under our Exit Facility. Information regarding these various obligations and commitments are included in our Annual Report on Form 10-KThe results of operations for the yearthree months ended DecemberMarch 31, 2016. There2024 and 2023 have been no significant changes in these obligations and commitments.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhancederived from our liquidity and capital resource positions or for any other purpose. However, as is customary in the oil and gas industry, we may, from time to time, have various contractual work commitments and/or letters of credit as described in our notes to the 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 during 2023.
The following table summarizes certain of the results of operations for the periods indicated. | | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | ($ In thousands except per unit amounts) | | | | | | | Oil and natural gas sales | | $ | 75,322 | | $ | 66,284 | Other revenues | | | 977 | | | 13,586 | Lease operating expense | | | 38,284 | | | 32,960 | Gathering, processing and transportation | | | 4,774 | | | 5,602 | Taxes other than income | | | 4,911 | | | 5,293 | Depreciation, depletion and amortization | | | 8,239 | | | 5,808 | General and administrative expense | | | 9,800 | | | 8,514 | Loss (gain) on commodity derivative instruments | | | 16,564 | | | (15,159) | Pipeline incident loss | | | 707 | | | 8,279 | Interest expense, net | | | 3,527 | | | 5,737 | Litigation settlement | | | — | | | 84,875 | Income tax (expense) benefit - current | | | (1,395) | | | (12,527) | Income tax (expense) benefit - deferred | | | 4,703 | | | 259,470 | Net income (loss) | | | (9,396) | | | 352,759 | | | | | | | | Oil and natural gas revenues: | | | | | | | Oil sales | | $ | 57,422 | | $ | 38,816 | NGL sales | | | 7,525 | | | 7,785 | Natural gas sales | | | 10,375 | | | 19,683 | Total oil and natural gas revenues | | $ | 75,322 | | $ | 66,284 | | | | | | | | Production volumes: | | | | | | | Oil (MBbls) | | | 786 | | | 535 | NGLs (MBbls) | | | 333 | | | 325 | Natural gas (MMcf) | | | 4,335 | | | 5,303 | Total (MBoe) | | | 1,842 | | | 1,745 | Average net production (MBoe/d) | | | 20.2 | | | 19.4 | | | | | | | | Average realized sales price (excluding commodity derivatives): | | | | | | | Oil (per Bbl) | | $ | 72.98 | | $ | 72.52 | NGL (per Bbl) | | | 22.61 | | | 23.92 | Natural gas (per Mcf) | | | 2.39 | | | 3.71 | Total (per Boe) | | $ | 40.89 | | $ | 37.99 | | | | | | | | Average unit costs per Boe: | | | | | | | Lease operating expense | | $ | 20.78 | | $ | 18.89 | Gathering, processing and transportation | | | 2.59 | | | 3.21 | Taxes other than income | | | 2.67 | | | 3.03 | General and administrative expense | | | 5.32 | | | 4.88 | Depletion, depreciation and amortization | | | 4.47 | | | 3.33 |
For the Three Months Ended March 31, 2024 Compared to the Three Months Ended March 31, 2023 We reported a net loss of $9.4 million compared to net income of $352.8 million for the three months ended March 31, 2024 and 2023, respectively. Oil, natural gas and NGL revenues were $75.3 million and $66.3 million for the three months ended March 31, 2024 and 2023, respectively. Average net production volumes were approximately 20.2 MBoe/d and 19.4 MBoe/d for the three months ended March 31, 2024 and 2023, respectively. The change in production volumes was primarily driven by Beta returning to production in April 2023. For the first quarter of 2023 Beta was offline. The average realized sales prices were $40.89 per Boe and $37.99 per Boe for the three months ended March 31, 2024 and 2023, respectively. The increase in oil, natural gas and NGL revenues and average realized sales price was primarily due to Beta returning to production in April 2023. Other revenues were $1.0 million and $13.6 million for the three months ended March 31, 2024 and 2023, respectively. The decrease in other revenues was primarily related to our receipt of LOPI insurance proceeds of $13.5 million for the three months ended March 31, 2023. We have not received LOPI insurance proceeds since payments under the LOPI policy terminated on March 31, 2023. Lease operating expenses were $38.3 million and $33.0 million for the three months ended March 31, 2024 and 2023, respectively. On a per Boe basis, lease operating expenses were $20.78 and $18.89 for the three months ended March 31, 2024 and 2023, respectively. The change in lease operating expense was primarily related to operating costs associated with Beta returning to production. During the first quarter of 2023, Beta was offline. Recent Accounting PronouncementsGathering, processing and transportation expenses were $4.8 million and $5.6 million for the three months ended March 31, 2024 and 2023, respectively. On a per Boe basis, gathering, processing and transportation expenses were $2.59 and $3.21 for the three months ended March 31, 2024 and 2023, respectively. The change in gathering processing and transportation expense was primarily due to lower gas volumes and the expiration of minimum volume commitments for our Oklahoma properties.
Taxes other than income were $4.9 million and $5.3 million for the three months ended March 31, 2024 and 2023, respectively. On a per Boe basis, taxes other than income were $2.67 and $3.03 for the three months ended March 31, 2024 and 2023, respectively. The decrease was primarily related to a reduction in production taxes due to lower natural gas commodity prices. In May 2014,DD&A expenses were $8.2 million and $5.8 million for the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 provides guidance concerningthree months ended March 31, 2024 and 2023, respectively. The increase in DD&A expense was primarily driven by production at Beta. During the recognitionfirst quarter of 2023, Beta was offline.
General and measurementadministrative expenses were $9.8 million and $8.5 million for the three months ended March 31, 2024 and 2023, respectively. The change in general and administrative expenses was primarily related to (i) an increase of revenue from contracts with customers. The objective$0.6 million in stock compensation expense, (ii) an increase of ASU 2014-09 is$0.3 million in severance payments, (iii) and an increase of $0.4 million in office lease expense related to increase the usefulnessearly termination of informationour Oklahoma office lease. Net loss on commodity derivative instruments of $16.6 million were recognized for the three months ended March 31, 2024, consisting of $20.8 million decrease in the fair value of open positions, partially offset by $4.3 million of cash settlements received on expired positions. Net gain on commodity derivative instruments of $15.2 million was recognized for the three months ended March 31, 2023, consisting of a $17.9 million increase in the fair value of open positions, partially offset by $2.7 million of cash settlements paid on expired positions. Pipeline incident loss was $0.7 million and $8.3 million for the three months ended March 31, 2024 and 2023, respectively. The costs reflect certain expenses not expected to be recovered under an insurance policy. 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. Litigation settlement was $84.9 million for the three months ended March 31, 2023, related to the settlement with the shipping companies and the containerships whose anchors struck the Company’s pipeline. See additional information discussed in Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. No litigation settlement was recorded for the three months ended March 31, 2024. Interest expense, net was $3.5 million and $5.7 million for the three months ended March 31, 2024 and 2023, respectively. The change in interest expense was primarily driven by lower outstanding borrowings, slightly lower interest rates and amortization of deferred issuance costs. In addition, in the first quarter of 2023, the Company wrote off $0.2 million in deferred issuance costs. Average outstanding borrowings under our Revolving Credit Facility were $115.2 million and $192.4 million for the three months ended March 31, 2024 and 2023, respectively. Current income tax expenses were $1.4 million and $12.5 million for the three months ended March 31, 2024 and 2023, respectively. See additional information discussed in Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. Deferred income tax benefits were $4.7 million and $259.5 million for the three months ended March 31, 2024 and 2023, respectively. Starting in the first quarter of 2023, we achieved three years of cumulative income which resulted in the release of the valuation allowance. See additional information discussed in Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. Adjusted EBITDA We include in this report the non-GAAP financial statements regardingmeasure 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: | ● | Impairment of goodwill and long-lived assets (including oil and natural gas properties); |
| ● | 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; |
| ● | Acquisition and divestiture related expenses; |
| ● | Reorganization items, net; |
| ● | Other non-routine items that we deem appropriate. |
Less: | ● | 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 Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the nature, timingresults 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 uncertaintyassessing a company’s financial performance, such as a company’s cost of revenues.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 have completedbelieve that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our reviewability 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 contractsthe Company’s net income (loss) and cash flows from operating activities to Adjusted EBITDA, our most directly comparable GAAP financial measures, for each revenue stream identified within our business and are currently finalizing our conclusion on any changes in revenue recognition upon adoption of the revised guidance.periods indicated. Reconciliation of Net Income (Loss) to Adjusted EBITDA | | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | | | | (In thousands) | Net income (loss) | | $ | (9,396) | | $ | 352,759 | Interest expense, net | | | 3,527 | | | 5,737 | Income tax expense (benefit) - current | | | 1,395 | | | 12,527 | Income tax expense (benefit) - deferred | | | (4,703) | | | (259,470) | DD&A | | | 8,239 | | | 5,808 | Accretion of AROs | | | 2,061 | | | 1,942 | Losses (gains) on commodity derivative instruments | | | 16,564 | | | (15,159) | Cash settlements (paid) received on expired commodity derivative instruments | | | 4,303 | | | (2,709) | Pipeline incident loss | | | 707 | | | 8,279 | Litigation settlement | | | — | | | (84,875) | Share-based compensation expense | | | 1,531 | | | 941 | Exploration costs | | | 41 | | | 26 | Acquisition and divestiture related expenses | | | 14 | | | — | Bad debt expense | | | 26 | | | — | Other | | | 592 | | | — | Adjusted EBITDA | | $ | 24,901 | | $ | 25,806 |
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA | | | | | | | | | For the Three Months Ended | | | March 31, | | | 2024 | | 2023 | | | | (In thousands) | Net cash provided by operating activities | | $ | 7,712 | | $ | 90,313 | Changes in working capital | | | 11,217 | | | (5,740) | Interest expense, net | | | 3,527 | | | 5,737 | Pipeline incident loss | | | 707 | | | 8,279 | Litigation settlement | | | — | | | (84,875) | Income tax expense (benefit) - current | | | 1,395 | | | 12,527 | Amortization and write-off of deferred financing fees | | | (304) | | | (461) | Exploration costs | | | 41 | | | 26 | Acquisition and divestiture related expenses | | | 14 | | | — | Other | | | 592 | | | — | Adjusted EBITDA | | $ | 24,901 | | $ | 25,806 |
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 assessments to date,our current oil and natural gas price expectations, we believe ASU 2014-09our cash flows provided by operating activities and availability under our Revolving Credit Facility will impactprovide us with the presentationfinancial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2024 development activities. However, future cash flows are subject to a number of future revenuesvariables, including the level of our oil and expenses by including certain transportationnatural gas production and gathering costs, along with various other fees such as compressionthe prices we receive for our oil and marketing fees net within revenues. The inclusion of these costs within revenuesnatural gas production, and significant additional capital expenditures will not impactbe required to more fully develop our revenue recognition, financial position, net income or cash flows. In addition, several industry interpretations are currently open for public comment.properties. We cannot quantitatively assessassure you that operations and other needed capital will be available on acceptable terms, or at all. For the remainder of 2024, we expect our primary funding sources to be from internally generated cash flow but retain the flexibility to utilize borrowings under our Revolving Credit Facility and/or to access the debt and equity capital markets. Impact of the Beta Pipeline Incident. There are remaining uncertainties surrounding the full impact of ASU 2014-09that the Incident will have on our financial statements until final consensus is reachedcondition and cash flow generation going forward. We have incurred and will continue to incur certain costs as a result of the Incident. However, in addition to the settlement amount disclosed elsewhere in this Quarterly Report on these various industry matters. OnceForm 10-Q that we received from the vessels that struck and damaged the Pipeline and their respective owners and operators, we carry customary insurance policies, which have covered a material portion of aggregate costs, including loss of production income insurance to offset loss of revenue resulting from suspended operations. The loss of production income insurance related to the Incident expired on March 31, 2023. We restarted operations at Beta in April 2023. We can provide no assurance that our coverage will adequately protect us against liability from all pending industry interpretations are addressed, we will finalize our assessment of ASU 2014-09.potential consequences, damages and losses related to the Incident. Capital Markets. We are in the process of evaluating the information technology and internal control changes that will be required for adoption based on our contract review process, but we do not currently anticipate material impactsany near-term capital markets activity, but we will continue to either information technology or internal controls. However, this assessment is pending conclusionevaluate the availability of various industry interpretations.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 applyenter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 50% - 75% of our estimated production from total proved developed producing reserves over a one-to-three-year period at any given point of time. We may, however, from time to time, hedge more or less than this approximate amount. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the modified retrospective approach upon adoptionpercentage 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. Capital Expenditures. Total capital expenditures were approximately $19.1 million for the three months ended March 31, 2024, which were primarily related to the development program at Beta, capital workovers and facilities upgrade projects at Beta and in Oklahoma and non-operated drilling and completion activities in 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. As of March 31, 2024, we had a working capital deficit (excluding commodity derivatives) of $21.4 million primarily due to accrued liabilities of $36.8 million, revenues payable of $20.8 million, and accounts payable of $21.7 million partially offset by accounts receivable of $36.5 million, prepaid expenses of $18.4 million and cash on hand of $3.0 million. Debt Agreement Revolving Credit Facility. On July 31, 2023, OLLC and Acquisitionco entered into the Revolving Credit Facility. The Revolving Credit Facility is a replacement in full of the Prior Revolving Credit Facility. The aggregate principal amount of loans outstanding under the Revolving Credit Facility as of March 31, 2024, was $115.0 million. As of March 31, 2024, we had approximately $20.0 million of available borrowings under our Revolving Credit Facility. The Company is required to maintain a minimum current ratio of 1.00 to 1.00, which is measured on the last day of each quarter. On March 31, 2024, the Company’s current ratio was 0.98 to 1.00. On May 2, 2024, the Company received a letter agreement from its lenders waiving any default or event of default as a result of such noncompliance related to the minimum current ratio requirement for the quarter ended March 31, 2024. As a result, the Company was in compliance with all financial covenants as of March 31, 2024. The Company expects to maintain a current ratio of 1.0 to 1.0 in future quarters. 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 standardquarterly 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 the Beta production facilities. As of March 31, 2024, our future commitment under this agreement was $6.8 million for the remainder of 2024 and $9.0 million per year until the escrow account is fully funded. 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. 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 three months ended March 31, 2024 and 2023 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 Three Months Ended | | | March 31, | | | 2024 | | 2023 | | | | (In thousands) | Net cash provided by operating activities | | $ | 7,712 | | $ | 90,313 | Net cash used in investing activities | | | (23,724) | | | (10,417) | Net cash used in financing activities | | | (1,745) | | | (67,141) |
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $7.7 million and $90.3 million for the three months ended March 31, 2024 and 2023, respectively. For the three months ended March 31, 2023, we received $84.9 million in connection with the settlement between the Company and the vessels that struck and damaged the pipeline and their respective owners and operators. Production volumes were approximately 20.2 MBoe/d and 19.4 MBoe/d for the three months ended March 31, 2024 and 2023, respectively. The change in production volumes was primarily driven by Beta returning to production in April 2023. For the first quarter of 2023 Beta was offline. The average realized sales price was $40.89 per Boe and $37.99 per Boe for the three months ended March 31, 2024 and 2023, respectively. The change in average realized sales price was primarily due to higher oil commodity prices and Beta coming back online. Net cash provided by operating activities for the three months ended March 31, 2024 included $4.3 million of cash received on expired commodity derivative instruments compared to $2.7 million of cash paid on expired commodity derivatives for the effective datethree months ended March 31, 2023. For the three months ended March 31, 2024, we had net losses on commodity derivative instruments of January 1, 2018.$16.6 million compared to a net gain of $15.2 million for the three months ended March 31, 2023. Investing Activities. Net cash used in investing activities for the three months ended March 31, 2024 was $23.7 million, of which $19.1 million was used for additions to oil and natural gas properties. In addition, we had a decrease of $1.5 million in our capital expenditures payable account. Net cash provided by investing activities for the three months ended March 31, 2023 was $10.4 million, of which $8.2 million was used for additions to oil and natural gas properties. In February 2016,Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our Beta properties. Additions to restricted investments were $2.5 million and $2.1 million during the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”)three months ended March 31, 2024 and 2023, respectively.
Financing Activities. ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee We had repayments of $25.0 million, offset by $25.0 million in borrowings for the three months ended March 31, 2024 related to record a ROU asset and a lease liability onour Revolving Credit Facility compared to net repayments of $65.0 million for the three months ended March 31, 2023. Off–Balance Sheet Arrangements As of March 31, 2024, we had no off–balance sheet for all leases with terms longer than 12 months. All leases create an asset andarrangements. Recently Issued Accounting Pronouncements For a liability for the lessee and therefore recognitiondiscussion of those lease assets and lease liabilities is required by ASU 2016-02. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginningrecent accounting pronouncements that will affect us, see Note 2 of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are in the initial evaluation and planning stagesNotes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for ASU 2016-02 and do not expect to move beyond this stage until completion of its evaluation of ASU 2014-09, which is expected to occur in the latter half of 2017.additional information. In July 2017, the FASB issued Accounting Standards Update 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We do not believe the adoption of ASU 2017-11 will have a material impact on its financial position, results of operations or cash flows.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments. The primary objectivesmaller reporting company as defined by Rule 12b-2 of the following information isExchange Act and are not required to provide forward-looking quantitative and qualitativethe information about our potential exposure to market risks. The disclosures are not meant to be precise indicatorsunder this item.
Table of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Condensed Consolidated Financial Statements — Note 4. Risk Management and Derivative Instruments.”Contents Commodity Price Exposure
We are exposed to market risk as the prices of oil, NGLs and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged and in the long-term, expect to hedge, a significant portion of our future production.
We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of September 30, 2017, we utilized fixed price swaps, collars and three way collars to reduce the volatility of oil and natural gas prices on a portion of our future expected oil and natural gas production.
For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At September 30, 2017, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:
| | 10% Increase | | 10% Decrease | | | | (in thousands) | | Gain (loss): | | | | | | Gas derivatives | | $ | (2,408 | ) | $ | 2,273 | | Oil derivatives | | $ | (5,482 | ) | $ | 5,473 | |
Interest Rate Risk
At September 30, 2017, we had indebtedness outstanding under our Exit Facility of $128.1 million, which bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. Assuming the Exit Facility is fully drawn, a one percent increase in interest rates for the three months ended September 30, 2017 would have resulted in a $0.4 million increase in interest cost, before capitalization.
At September 30, 2017, we did not have any interest rate derivatives in place and have not historically utilized interest rate derivatives. In the future, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing or future debt issues. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
ItemITEM 4. Controls and ProceduresCONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures DuringAs required by Rules 13a-15(b) and 15d-15(b) of the period covered by this report,Exchange Act, we have evaluated, under the supervision and with the participation of our management, carried out an evaluation ofincluding the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures pursuant to(as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act Rule 13a-15.Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to ensureprovide reasonable assurance that the information required to be disclosed by us in the reports that we file withunder the SECExchange 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,SEC. Based upon the evaluation, the principal executive officer and that such information is accumulated and communicated to our management, including our President and Chief Executive Officer and our Vice President and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures. Based on that evaluation, our President and Chief Executive Officer and our Vice President and Chief Accounting Officerprincipal financial officer have concluded that as of September 30, 2017, theseour disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2024. We believe that our internal controls and ensured thatprocedures are still functioning as designed and were effective for the information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported on a timely basis.most recent quarter.
ChangesChange in Internal Control overOver Financial Reporting
There were noNo changes in our internal control over financial reporting occurred during the most recent quarter ended September 30, 2017, 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. PART II - II—OTHER INFORMATION ITEM 1.LEGAL PROCEEDINGS. Item 1. Legal Proceedings
From time to time, we are party to variousFor a discussion of the legal proceedings arising inassociated with the ordinary courseIncident, see Note 16 of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. See “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Condensed Consolidated Financial Statements — Note 14. Commitmentsincluded under “Item 1. Financial Statements” of this quarterly report and Contingencies”, which is incorporatedthe annual financial statements and related notes included in this itemour 2023 Form 10-K.
Future litigation may be necessary, among other things, to defend ourselves by reference.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. ItemITEM 1A. Risk Factors
RISK FACTORS. Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Reportquarterly 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. In addition There have been no material changes to the other information set forth in this report, you should carefully consider therisk factors discussed below and describeddisclosed in Part I, Item 1A ofin our Annual Report on2023 Form 10-K for the year ended December 31, 2016, filed with the SEC on March 30, 2017.10-K.
Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of saltwater produced in conjunction with our hydrocarbons, which could limit our ability to produce oil and gas economically and have a material adverse effect on our business.
We dispose of large volumes of saltwater produced in conjunction with the oil and natural gas produced from our drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, the applicable legal requirements may be subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements.
The adoption and implementation of any new laws, regulations, or directives that restrict our ability to dispose of saltwater by plugging back the depths of disposal wells, reducing the volume of oil and natural gas wastewater disposed in such wells, restricting disposal well locations, or requiring us to shut down disposal wells, could require the Company to cease operations at a substantial number of its oil and natural gas wells, which would have a material adverse effect on our ability to produce oil and gas economically and, accordingly, could materially and adversely affect our business, financial condition and results of operations.
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS. Item 2. Unregistered Sales of Equity Securities and Use of ProceedsThe following table summarizes our repurchase activity during the three months ended March 31, 2024:
| | | | | | | | | | | | | | | | | 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) | | | | | | | | | | January 1, 2024 - January 31, 2024 | | 29,412 | | $ | 5.96 | | — | | n/a | February 1, 2024 - February 29, 2024 | | 137,637 | | $ | 6.04 | | — | | n/a | March 1, 2024 - March 31, 2024 | | 60,162 | | $ | 6.05 | | — | | 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. |
None.
ItemITEM 3. Defaults Upon Senior Securities
DEFAULTS UPON SENIOR SECURITIES. None. ItemITEM 4. Mine Safety Disclosures
MINE SAFETY DISCLOSURES. Not applicable. ItemITEM 5. Other Information
OTHER INFORMATION. None. Item 6. Exhibits
Exhibits included in this Quarterly Report are listed in the Exhibit Index and incorporated herein by reference.
EXHIBIT INDEXITEM 6.EXHIBITS.
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Exhibit
Number | | | | | Exhibit Description
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| 2.1Description
| | First Amended Joint Chapter 11 Plan Of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate, dated September 28, 2016 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on October 4, 2016, and incorporated herein by reference).
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| | | 3.1 | | — | | Second Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed on October 21, 2016, and incorporated herein by reference). | | | | | | 3.2 | | — | | Certificate of Amendment to the Second Amended and Restated BylawsCertificate of Incorporation of Midstates Petroleum Company, Inc. (filed as, dated August 6, 2019 (incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form 8-A filed on October 21, 2016, and incorporated herein by reference). | | | | 4.1
| | Warrant Agreement, dated as3.1 of October 21, 2016 between Midstates Petroleum Company, Inc. and American Stock Transfer & Trust Company, LLC (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 001-35512) filed on October 27, 2016, and incorporated herein by reference)August 6, 2019).
| | | | | | 4.23.3
| | — | | Warrant Agreement, dated asThird Amended and Restated Bylaws of October 21, 2016, between Midstates Petroleum Company, Inc. and American Stock Transfer & Trust Company, LLC (filed asAmplify Energy Corp. (incorporated by reference to Exhibit 4.2 to3.3 of the Company’s CurrentQuarterly Report on Form 8-K10-Q (File No. 001-35512) filed on October 27, 2016, and incorporated herein by reference)November 15, 2021).
| | | | 10.1
| | First Amendment to Senior Secured Credit Agreement, dated May 24, 2017, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, as borrower, SunTrust Bank, as administrative agent, and certain lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 26, 2017, and incorporated herein by reference).
| | | | 10.2
| | Separation Agreement and General Release of Claims, dated as of June 7, 2017, by and between Midstates Petroleum Company, Inc. and Nelson M. Haight (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 7, 2017, and incorporated herein by reference).
| | | | 10.3
| | Amendment No. 1 to Executive Employment Agreement, dated as of August 22, 2017, by and between Midstates Petroleum Company, Inc. and Frederic F. Brace (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 25, 2017, and incorporated herein by reference).
| | | | 10.4
| | Executive Employment Agreement, effective as of November 1, 2017, by and between Midstates Petroleum Company, Inc. and David J. Sambrooks (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 26, 2017, and incorporated herein by reference).
| | | | 10.5
| | Form of Restricted Stock Unit Award Agreement, effective as of November 1, 2017, by and between Midstates Petroleum Company, Inc. and David J. Sambrooks (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 26, 2017, and incorporated herein by reference).
| | | | 10.6
| | Form of Performance Stock Unit Award Agreement, effective as of November 1, 2017, by and between Midstates Petroleum Company, Inc. and David J. Sambrooks (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on October 26, 2017, and incorporated herein by reference).
| | | | 10.7
| | Borrowing Base Redetermination Agreement, dated as of October 27, 2017, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, the lenders party thereto and SunTrust Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 1, 2017, and incorporated herein by reference).
| | | | 31.1* | | Sarbanes-Oxley Section 302 certification of Principal Executive Officer
| — | | Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. | | | | | | 31.2* | | Sarbanes-Oxley Section 302 certification of Principal Financial Officer
| — | | Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. | | | | | | 32.1** | | Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
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* | | Filed herewithas an exhibit to this Quarterly Report on Form 10-Q. |
** | | Furnished herewithas an exhibit to this Quarterly Report on Form 10-Q |
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. | | | | | MIDSTATES PETROLEUM COMPANY, INC.Amplify Energy Corp.
| | (Registrant) | Dated: November 14, 2017
| | | | Date: | May 8, 2024 | By: | /s/ David J. SambrooksJames Frew | | David J. Sambrooks
| Name: | James Frew | | | Title: | Senior Vice President and Chief ExecutiveFinancial Officer | | (Principal Executive Officer)
| | | | | | | Date: | May 8, 2024 | Dated: November 14, 2017By:
| /s/ Richard W. McCulloughEric Dulany | | Richard W. McCullough
| Name: | Eric Dulany | | | Title: | Vice President and Chief Accounting Officer | | (Principal Financial Officer and Principal Accounting Officer)
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