SEC Info - Amplify Energy Corp. - ‘10-K’ for 12/31/19

December 31,

through

2019

2018

Major customers:

Phillips 66

27%

23%

19%

Sinclair Oil & Gas Company

21%

19%

20%

CIMA Energy

n/a

10%

11%

n/a

BP America Production Company

13%

n/a

10%

The production sales agreements covering our properties contain customary terms and conditions for the oil and natural gas industry and provide for sales based on prevailing market prices. A majority of those agreements have terms that renew on a month-to-month basis until either party gives advance written notice of termination.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether and we were unable to replace them, the loss of any such customer could have a detrimental effect on our production volumes and revenues in general.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with industry standards. More thorough title investigations are customarily made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests.

Derivative Activities

We enter into commodity derivative contracts with unaffiliated third parties, generally lenders under our Revolving Credit Facility or their affiliates, to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 25% - 50% of our estimated production from total proved developed producing reserves over a one-to-three-year period at any given point of time to satisfy the hedging covenants in our Revolving Credit Facility and pursuant to our internal policies. We may, however, from time to time, hedge more or less than this approximate amount.

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our Revolving Credit Facility) to fixed interest rates.

It is our policy to enter into derivative contracts only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our Revolving Credit Facility are counterparties to our derivative contracts. We will continue to evaluate the benefit of employing derivatives in the future. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information.

Competition

We operate in a highly competitive environment for acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us.

Seasonal Nature of Business

The price we receive for our natural gas production is impacted by seasonal fluctuations in demand for natural gas. The demand for natural gas typically peaks during the coldest months and tapers off during the milder months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Hydraulic Fracturing

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete, except in our offshore wells. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. Our proved non-producing and proved undeveloped reserves make up 25% of the total proved reserves with approximately 75% of these requiring hydraulic fracturing as of December 31, 2019.

We believe we have followed and continue to substantially follow applicable industry standard practices and legal and regulatory requirements for groundwater protection in our hydraulic fracturing operations which are subject to supervision by state and federal regulators (including the U.S. Bureau of Land Management (the “BLM”) on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design is intended to essentially eliminate a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abnormal change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand, and the fluids are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it into approved disposal or injection wells. We currently do not discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, see “— Environmental, Occupational Health and Safety Matters and Regulations — Hydraulic Fracturing.”

Insurance

In accordance with customary industry practice, we maintain insurance against many, but not all, potential losses or liabilities arising from our operations and at costs that we believe to be economic. We regularly review our risks of loss and the cost and availability of insurance and revise our insurance accordingly. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses. We currently have insurance policies that include the following:

• Commercial General Liability;	• Oil Pollution Act Liability;
• Primary Umbrella / Excess Liability;	• Pollution Legal Liability;
• Property;	• Charterer’s Legal Liability;

• Workers’ Compensation;	• Non-Owned Aircraft Liability;
• Employer’s Liability;	• Automobile Liability;
• Maritime Employer’s Liability;	• Directors & Officers Liability;
• U.S. Longshore and Harbor Workers’;	• Employment Practices Liability;
• Energy Package/Control of Well;	• Crime; and
• Loss of Production Income (offshore only);	• Fiduciary.

We continuously monitor regulatory changes and comments and consider their impact on the insurance market, along with and our overall risk profile. As necessary, we will adjust our risk and insurance program to provide protection at a level we consider appropriate, while weighing the cost of insurance against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations could lead to changes in underwriting standards, limitations on scope and amount of coverage, and higher premiums, including possible increases in liability caps for claims of damages from oil spills.

Environmental, Occupational Health and Safety Matters and Regulations

General

Our oil and natural gas development and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. In addition, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. Although President Trump has sought to roll back certain federal regulations related to environmental protection, new laws and regulations continue to be enacted, particularly at the state level, and the long-term trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

The following is a summary of the more significant existing environmental, occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

BOEM & BSEE

Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters. The Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) have broad authority to regulate our oil and gas operations associated with our Beta properties.

BOEM is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act (“NEPA”) analysis and environmental studies. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. In July 2016, BOEM issued updated guidance for determining if and when additional security is required for Outer Continental Shelf (“OCS”) leases, pipeline rights-of-way and rights-of-use and easement. The new criteria may require lessees or operators to take additional steps to demonstrate that they have the financial ability to carry out their obligations. In June 2017, BOEM announced that the implementation timeline would be extended, except in circumstances where there is a substantial risk of nonperformance of the interest holder’s obligations.

BSEE is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and training and environmental compliance programs. BSEE regulations require offshore production facilities and pipelines located on the OCS to meet stringent engineering and construction specifications, and BSEE has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas, prohibit the flaring of liquid hydrocarbons and govern the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities.

BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated and we may be subject to civil or criminal liability.

In November 2018, a federal court prohibited BOEM and BSEE from approving any plans or issuing permits involving hydraulic fracturing and/or acid well stimulation on the Pacific OCS until the agencies complete consultation with the U.S. Fish and Wildlife Service under the Endangered Species Act and submit a consistency determination under the Coastal Zone Management Act to the California Coastal Commission. Although we do not use either hydraulic fracturing or acid stimulation routinely in connection with our operations on the Beta properties, delays in the approval or refusal of plans and issuance of permits by BOEM or BSEE because of staffing, economic, environmental, legal or other reasons (or other actions taken by BOEM or BSEE) could adversely affect our offshore operations. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations. Also, in addition to permits and approvals required by BOEM and BSEE, approvals and permits are required from other agencies for the oil and gas operations associated with our Beta properties, such as the U.S. Coast Guard, the EPA, U.S. Department of Transportation and the South Coast Air Quality Management District.

Hazardous Substances and Waste Handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also referred to as the Superfund law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Also, comparable state statutes may not contain a similar exemption for petroleum, and it is also not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Oil Pollution Act of 1990 (“OPA”) is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills. For example, the California Department of Fish and Wildlife’s Office of Oil Spill Prevention and Response have adopted oil-spill prevention regulations that overlap with federal regulations.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA entered into a consent decree requiring it to review its regulation of oil and gas waste. In April 2019, the EPA determined that revisions to the RCRA regulations were not required, concluding that any adverse effects related to oil and gas waste are more appropriately and readily addressed within the framework of existing state regulatory programs. However, any such changes to state programs could result in an increase in our costs to manage and dispose of oil and gas waste, which could have a material adverse effect on our maintenance capital expenditures and operating expenses.

It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials (“NORM”). NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes into contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Administrative, civil and criminal penalties can be imposed for failure to comply with hazardous substance and waste handling requirements. We believe that we are in substantial compliance with the requirements of CERCLA, OPA, RCRA, and other applicable federal and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our hazardous substances and wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water Discharges

The Federal Water Pollution Control Act (also known as the Clean Water Act), the Safe Drinking Water Act (“SDWA”), the OPA and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). In June 2015, the EPA and the Corps issued a rule to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, which was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit in October 2015 pending resolution of several legal challenges. The EPA and the Corps proposed a rule in July 2017 to repeal the WOTUS rule and announced their intent to issue a new rule defining the CWA's jurisdiction. In January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the WOTUS rule resides with the federal district courts and not the courts of appeal; the decision lifted the nationwide stay, resulting in a patchwork application of the rule in some states, but not in others. In October 2019, the EPA issued a final rule repealing the WOTUS rule, which became effective in December 2019. The repeal rule has already been challenged in multiple federal district courts, including in New Mexico, New York, and South Carolina. In January 2020, the EPA and the Corps announced the final rule revising the definition of WOTUS. The new definition narrows the scope of waters that are covered as jurisdictional. Several groups have already announced their intention to challenge the new WOTUS rule. As a result, future implementation is uncertain at this time. To the extent a stay of this rule or the implementation of a revised rule expands the scope of the CWA's jurisdiction, or impacts available agency resources, the Company could face increased costs and/or delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of storm water or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits or specify other requirements for discharges or operations that may impact groundwater conditions. These same regulatory programs may also limit the total volume of water that can be discharged, hence limiting the rate of development and requiring us to incur compliance costs. Additionally, we are required to develop and implement spill prevention, control and countermeasure (“SPCC”) plans, in connection with on-site storage of significant quantities of oil.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Additionally, obtaining permits has the potential to delay the development of natural gas and oil projects. We maintain all required discharge permits necessary to conduct our operations and we believe we are in substantial compliance with their terms.

In addition, in some instances, the operation of underground injection wells for the disposal of wastewater has been alleged to cause earthquakes. For example, in February 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. In some jurisdictions, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity or resulted in stricter regulatory requirements relating to the location and operation of underground injection wells. Such issues have also led to lawsuits by private parties alleging damages relating to induced seismicity. For example, the Railroad Commission of Texas (the “Commission”) requires applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey, which are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The Commission is authorized to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Commission is also considering new restrictions that could limit the volume and pressure of produced water injected into disposal wells. Additionally, we conduct oil and gas drilling and production operations in the Mississippian Lime formation in Oklahoma, a high-water play, which requires us to dispose of large volumes of saltwater generated as part of our operations. In 2015, the Oklahoma Geological Survey attributed an increase in seismic activity in Oklahoma to saltwater disposal wells in the Arbuckle formation. Around the same time, the Oklahoma Corporation Commission (“OCC”), whose Oil and Gas Conservation Division regulates oil and gas operations in Oklahoma, began issuing regulations targeting saltwater disposal activities in certain areas of interest within the Arbuckle formation. The regulations include operational requirements (i.e., mechanical integrity testing of wells permitted for disposal of 20,000 or more barrels of water per day, daily monitoring and recording of well pressure and discharge volume), as well as orders to shut-in wells, reduce well depths, or decrease disposal volumes. Under these regulations, in 2016 and 2017, the OCC ordered us to limit the volume of saltwater disposed of in saltwater disposal wells in the Arbuckle formation, and it established caps for ten of our saltwater disposal wells in February 2017. To ensure that we had an adequate number of wells for disposal, we secured permits for additional saltwater disposal wells outside of the Arbuckle formation. We timely satisfied all OCC saltwater disposal requirements, while maintaining our production base without any negative material impact. However, any future orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect or curtail our operations.

Hydraulic Fracturing

We use hydraulic fracturing extensively in our onshore operations, but not our offshore operations. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. In June 2016, the EPA finalized wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works; for certain facilities, compliance was required by August 2019. This restriction of disposal options for hydraulic fracturing waste and other changes to environmental requirements may result in increased costs.

In addition, in March 2015, the BLM published a final rule governing hydraulic fracturing on federal and Indian lands. The rule required public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures and the depths of all usable water. Following years of litigation, the BLM rescinded the rule in December 2017. However, several environmental groups and states have challenged the BLM’s rescission of the rule in ongoing litigation.

Several states have also adopted, or are considering adopting, regulations requiring the disclosure of the chemicals used in hydraulic fracturing and/or otherwise imposing additional requirements for hydraulic fracturing activities. For example, Oklahoma requires oil and gas producers to report the chemicals they use in hydraulic fracturing to FracFocus.org, a national hydraulic fracturing chemical registry, or to the OCC, which will convey the information to FracFocus.org. The Louisiana Department of Natural Resources has adopted rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, Texas requires oil and natural gas operators to disclose to the Commission and the public the chemicals used in the hydraulic fracturing process, as well as the total volume of water used. Texas has also imposed requirements for drilling, putting pipe down and cementing wells, and testing and reporting requirements.

Certain governmental reviews have been conducted that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, in December 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. The EPA has also issued a draft study of onshore conventional and unconventional oil and gas extraction wastewater management, and conducted a study of private wastewater treatment facilities, also known as centralized waste treatment (“CWT”) facilities, accepting oil and gas extraction wastewater. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated various other aspects of hydraulic fracturing. In addition, as discussed above, BOEM and BSEE completed a study in May 2016 regarding the potential environmental impacts of well-stimulation practices on the Pacific OCS. These studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Additionally, a number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. We believe that we follow standard industry practices and legal requirements applicable to our hydraulic fracturing activities. Nonetheless, in the event of new or more stringent federal, state or local legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater or otherwise have negative impacts.

In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. For example, the U.S. Congress has from time to time considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Air Emissions

The federal Clean Air Act, as amended (“CAA”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. The South Coast Air Quality Management District (“SCAQMD”) is a regulatory subdivision of the State of California and responsible for air pollution control from stationary sources within Orange County and designated portions of Los Angeles, Riverside, and San Bernardino Counties. Our Beta properties and associated facilities are subject to regulation by the SCAQMD. Federal, SCAQMD, and other state laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.

The New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs under the CAA impose specific requirements affecting the oil and gas industry for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants, completions and certain other equipment. Periodic review and revision of these rules by federal and state agencies may require changes to our operations, including possible installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business. For example, in April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; the litigation is ongoing. In August 2019, the EPA issued a proposed rule to rescind the methane requirements for certain sources in the production and processing segments of the oil and gas industry; the rulemaking has not been finalized. Similarly, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of regulations it previously enacted to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands; this rule has been challenged in ongoing litigation. Any future changes to the NSPS and NESHAP programs, and other air quality programs, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs and could adversely impact our business.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. For example, the EPA, as well as the BLM, have issued rules to reduce methane emissions from oil and natural gas production and processing operations, which regulations are discussed in more detail above under the caption “Air Emissions.” Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, the EPA has adopted regulations requiring the monitoring and annual reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which include certain of our operations. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of states have taken legal measures to reduce emissions of GHGs, including through the planned development of GHGs emission inventories and/or regional GHGs cap and trade programs. In addition, on an international level, the United States was one of 175 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emission reduction goals beginning in 2020. However, on June 1, 2017, President Trump announced that the United States will withdraw from the Paris Agreement the withdrawal was initiated in November 2019 and is expected to be completed in November 2020. Various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. Any GHG regulation could increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance or have caused other redressable injuries under federal and/or state common law. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations.

Moreover, any legislation or regulatory programs to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities. Finally, it should be noted that most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our development and production operations.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the U.S. Departments of the Interior and Agriculture, to evaluate major federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency typically prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact statement that is made available for public review and comment. In January 2020, the White House’s Council on Environmental Quality issued a proposed rulemaking to amend the NEPA implementing regulations intended to streamline the environmental review process. The proposed rules would shorten the time for review as well as eliminate the requirement to evaluate cumulative impacts. The potential impacts of this proposed rule on our business are uncertain at this time. All of our current development and production activities, as well as proposed development plans, on federal lands, including those in the Pacific Ocean, require governmental permits that are subject to the requirements of NEPA. This environmental review process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position.

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. For example, under a new OSHA standard limiting respirable silica exposure, the oil and gas industry must implement engineering controls and work practices to limit exposures below the new limits by June 2021. Failure to comply with OSHA requirements can lead to the imposition of penalties. We believe that our operations are in substantial compliance with the OSHA requirements.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on our assets. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues in the U.S. Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

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the location of wells;

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the method of drilling and casing wells;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells;

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transportation of materials and equipment to and from our well sites and facilities;

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transportation and disposal of produced fluids and natural gas; and

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notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Sale and Transportation of Gas and Oil

The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the construction and operations of interstate gas pipeline facilities and the rates terms and conditions of service under which companies provide interstate transportation of gas, oil and other liquids by pipeline. Although the FERC does not have jurisdiction over the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. These agency actions have been intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

The FERC and other federal agencies, the U.S. Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any such proposal will affect us any differently than it would affect other gas or oil producers with which we compete.

The Beta properties include the San Pedro Bay Pipeline Company, which owns and operates an offshore crude oil pipeline. This pipeline is subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, must be just and reasonable and not unduly-discriminatory. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly. The FERC has established a formulaic methodology for oil and liquids pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Effective July 1, 2016, the current index for the five-year period ending July 2021 is the producer price index for finished goods plus an adjustment factor of 1.23 percent. The San Pedro Bay Pipeline Company uses the indexing methodology to change its rates.

The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. BOEM/BSEE has established formal and informal complaint procedures for shippers that believe they have been denied open and nondiscriminatory access to transportation on the OCS.

The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates the safety of all pipeline transportation in or affecting interstate or foreign commerce, including pipeline facilities on the OCS. The San Pedro Bay pipeline is subject to regulation by the PHMSA. In recent years, PHMSA has been active in proposing and finalizing additional regulations for natural gas and hazardous liquids pipelines. For example, in January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to a high consequence areas (“HCA”). The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure. In addition, in April 2016, PHMSA proposed a rule regarding the safety of natural gas transmission pipelines and gas gathering pipelines. In October 2019, PHMSA issued a final rule on the natural gas transmission lines portion of the April 2016 rulemaking, and PHMSA is expected to finalize the gathering lines portion in 2020. If the pending gathering-pipeline portion of the rulemaking ultimately includes a final rule that applies similar requirements to gathering lines as the final rule for natural gas transmission lines, some gathering pipeline operators may be forced to reduce their allowable operating pressures, which would reduce the amount of capacity available to the Company. As PHMSA has yet to finalize this rulemaking as applied to gathering lines, however, it is uncertain what impact the final rule may have on the Company.

Moreover, effective April 2017, the PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to up to $218,649 per violation per day and up to $2,186,465 for a related series of violations. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulation. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Anti-Market Manipulation Laws and Regulations

The FERC with respect to the purchase or sale of natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction and the Federal Trade Commission with respect to petroleum and petroleum products, operating under various statutes have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order repayment or disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Derivatives Regulation

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010 (“Dodd-Frank Act”). This legislation called for the Commodities Futures Trading Commission (“CFTC”) to regulate certain markets for derivative products, including over-the-counter (“OTC”) derivatives. The CFTC has issued several new relevant regulations and rulemakings to implement Dodd-Frank Act the mandate to cause significant portions of derivatives markets to clear through clearinghouses, along with other mandated changes. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The CFTC’s final rules were challenged in court by two industry associations and were vacated and remanded by a federal district court. Subsequently, the CFTC proposed new rules in November 2013 and December 2016 In January 2020, the CFTC withdrew the 2013 and 2016 proposals, and issued a new proposed rule, which includes limits on positions in (1) certain “Core Referenced Futures Contracts,” including contracts for several energy commodities; (2) futures and options on futures that are directly or indirectly linked to the price of a Core Referenced Futures Contract, or to the same commodity for delivery at the same location as specified in that Core Referenced Futures Contract; and (3) economically equivalent swaps. The proposal also includes exemptions from position limits for bona fide hedging activities. The proposal is not yet final, and it remains subject to public comment and subsequent revision by the CFTC. Consequently, the impact of the proposed rule on the Company and its counterparties is uncertain at this time.

The Dodd-Frank Act and new, related regulations may prompt counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may become less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations. Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.

Our sales of oil and natural gas are also subject to anti-manipulation and anti-disruptive practices authority under (i) the Commodity Exchange Act (“CEA”), as amended by the Dodd-Frank Act, and regulations promulgated thereunder by the CFTC, and (ii) the Energy Independence and Security Act of 2007 (“EISA”) and regulations promulgated thereunder by the FTC. The CEA, as amended by the Dodd-Frank Act, prohibits any person from using or employing any manipulative or deceptive device in connection with any swap, or a contract for sale of any commodity, or for future delivery on such commodity, in contravention of the CFTC’s rules and regulations. It also prohibits knowingly delivering or causing to be delivered false, misleading or inaccurate reports concerning market information or conditions that affect or tend to affect the price of any commodity. The FTC’s Petroleum Market Manipulation Rule, issued pursuant to EISA, prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. Under both the CEA and the EISA, fines for violations can be up to $1,000,000 per day per violation (subject to adjustment for inflation) and certain knowing or willful violations may also lead to a felony conviction.

Additional proposals and proceedings that may affect the crude oil and natural gas industry are pending before the U.S. Congress, federal agencies and the courts. The Company cannot predict the ultimate impact these proposals may have on its crude oil and natural gas operations, but the Company does not expect any such action to affect the Company differently than it will affect other gas or oil producers with which we compete.

State Regulation

Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, the baseline Texas severance tax on oil and gas is 4.6% of the market value of oil produced and 7.5% of the market value of gas produced and saved. A number of exemptions from or reductions of the severance tax on oil and gas production is provided by the State of Texas which effectively lowers the cost of production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

As of December 31, 2019, the Company had 230 employees. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Offices

Our principal executive office is located at 500 Dallas Street, Suite 1700, Houston, Texas 77002. Our main telephone number is (713) 490-8900.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at www.amplifyenergy.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. Our website also includes our Code of Business Conduct and Ethics, Corporate Governance Guidelines and the charters of our audit committee, compensation committee and nominating & governance committee. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

The SEC maintains a website that contains reports, proxy and information statements, and other information regarding the Company at www.sec.gov.

ITEM 1A.

RISK FACTORS

Our business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of this annual report, may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to Our Business

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

Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:

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the regional, domestic and foreign supply of oil, natural gas and NGLs;

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the level of commodity prices and expectations about future commodity prices;

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the level of global oil and natural gas exploration and production;

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localized supply and demand fundamentals, including the proximity and capacity of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;

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the cost of exploring for developing, producing and transporting reserves;

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the price and quantity of foreign imports;

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political and economic conditions in oil producing countries;

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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

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speculative trading in crude oil and natural gas derivative contracts;

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the level of consumer product demand;

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weather conditions and other natural disasters;

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risks associated with operating drilling rigs;

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technological advances affecting exploration and production operations and overall energy consumption;

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domestic and foreign governmental regulations and taxes;

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the impact of energy conservation efforts;

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the continued threat of terrorism and the impact of military and other action;

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the price and availability of competitors’ supplies of oil and natural gas and alternative fuels; and

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overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2019, the NYMEX-WTI oil future price ranged from a high of $76.41 per Bbl to a low of $26.21 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.88 per MMBtu to a low of $1.49 per MMBtu. For the year ended December 31, 2019, the West Texas Intermediate posted prices ranged from a low of $46.54 per Bbl on January 2, 2019 to a high of $66.30 per Bbl on April 23, 2019 and NYMEX Henry Hub spot market price ranged from a low of $1.82 per MMBtu on December 30, 2019 to a high of $4.25 per MMBtu on March 4, 2019. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have sustained depressed realized prices during this period and are generally correlated with the price of oil. A further or extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition.

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

As discussed above, oil, natural gas and NGL prices have experienced significant volatility over the past few years. A further or extended decline in commodity prices could render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to fund our operations.

We recognized $2.2 million impairment expense for certain unproved leasehold costs in Oklahoma for the year ended December 31, 2019. No impairment was recognized for the year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017, respectively. A further or extended decline in commodity prices may cause us to recognize additional impairments in the value of our oil and natural gas properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our Revolving Credit Facility.

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

Under our Revolving Credit Facility, we are required to maintain (i) as of the date of determination, a maximum total debt to EBITDAX ratio of 4.00 to 1.00, and (ii) a current ratio of not less than 1.00 to 1.00. If we were to violate any of the covenants under the Revolving Credit Facility and were unable to obtain a waiver or amendment, it would be considered a default after the expiration of any applicable grace period. If we were in default under the Revolving Credit Facility, then the lenders may exercise certain remedies including, among others, declaring all borrowings outstanding thereunder, if any, immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due, because we might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Revolving Credit Facility are secured by mortgages on not less than 85% of the PV-9 value of our oil and gas properties (and at least 85% of the PV-9 value of the proved, developed and producing oil and gas properties), and if we are unable to repay our indebtedness under our Revolving Credit Facility, the lenders could seek to foreclose on our assets.

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

Restrictive covenants in our Revolving Credit Facility impose significant operating and financial restrictions on us and our subsidiaries. These restrictions limit our ability to, among other things:

• incur additional liens;

• incur additional indebtedness;

• merge, consolidate or sell our assets;

• pay dividends or make other distributions or repurchase or redeem our stock;

• make certain investments; and

• enter into transactions with our affiliates.

The Revolving Credit Facility also requires us to comply with certain financial maintenance covenants as discussed above. A breach of any of these covenants could result in a default under the Revolving Credit Facility. If a default occurs and remains uncured or unwaived, the administrative agent or majority lenders under the Revolving Credit Facility may elect to declare all borrowings outstanding thereunder, if any, together with accrued interest and other fees, to be immediately due and payable. The administrative agent or majority lenders under the Revolving Credit Facility would also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay our indebtedness when due or declared due, the administrative agent will also have the right to proceed against the collateral pledged to it to secure the indebtedness under the Revolving Credit Facility. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.

We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants in the Revolving Credit Facility. The terms and conditions of the Revolving Credit Facility affect us in several ways, including:

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requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

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increasing our vulnerability to economic downturns and adverse developments in our business;

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limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

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placing restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

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placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

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limiting management’s discretion in operating our business.

Our lenders periodically redetermine the amount we may borrow under our Revolving Credit Facility, which may materially impact our operations.

Our Revolving Credit Facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Accordingly, declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute on our business plans. Any reduction in the borrowing base would materially and adversely affect our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations. In addition, as hedges roll off, the borrowing base is subject to further reduction. Our Revolving Credit Facility requires us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of notice to do so. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the Revolving Credit Facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under the Revolving Credit Facility.

We may be able to incur substantially more debt, which could exacerbate the risks associated with our indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Revolving Credit Facility. If new debt is added to our current debt levels, the related risks that we now face could increase. These risks could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to satisfy our obligations under our outstanding indebtedness.

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

Borrowings under our Revolving Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Interest Rate Risk” included under Part II of this Annual Report for further information regarding interest rate sensitivity.

Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.

We intend to maintain a portfolio of commodity derivative contracts covering at least 25% - 50% of our estimated production from proved developed producing reserves over a one-to-three-year period at any given point in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations, at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil, natural gas and NGL prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets or other unforeseen events could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of a derivative contract and, accordingly, prevent us from realizing the benefit of such a derivative contract.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could significantly reduce our cash flow and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, our California oil typically has a lower gravity, and a portion has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil requires more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. These discounts, if significant, could reduce our cash flows and adversely affect our results of operations and financial condition.

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

It is not possible to measure underground accumulations of oil or natural gas in an exact way. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

In order to prepare our estimates, we must project production rates and timing of operating and development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.

The process also requires economic assumptions about matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds.

Actual future production, oil prices, natural gas prices, revenues, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves shown in this report, or standardized measure, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the FASB, we base the estimated discounted future net cash flows from our proved reserves on the trailing 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements, which is required by the SEC and FASB, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

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

Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would materially and adversely affect our business, financial condition and results of operations.

We may be subject to risks in connection with divestitures and acquisitions.

We may sell any of our core or non-core assets in order to increase capital resources available for other core assets, create organizational and operational efficiencies or for other purposes. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets on terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific action.

In addition, in the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. As a result, our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

Our acquisition and development operations will require additional capital that may not be available.

Our business is capital intensive and requires substantial expenditures to maintain currently producing wells, to make the acquisitions and/or conduct the development activities necessary to replace our reserves, to pay expenses and to satisfy our other obligations. Low oil and natural gas prices, declines in the trading price of our common stock and concern about the global financial markets may limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, and could limit our ability to obtain additional or continued funding under our Revolving Credit Facility or obtain any funding at all.

If we reduce our capital spending in an effort to conserve cash, this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flow from operations and income. Further, if the borrowing base under our Revolving Credit Facility decreases, or our revenues decrease, as a result of lower oil or natural gas prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash flows.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then-realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of our development and production activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our development and production operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

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high costs, shortages or delivery delays of rigs, equipment, labor, electrical power or other services;

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unusual or unexpected geological formations;

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composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;

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unexpected operational events and conditions;

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failure of down hole equipment and tubulars;

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loss of wellbore mechanical integrity;

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failure, unavailability or shortage of capacity of gathering and transportation pipelines, or other transportation facilities;

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human errors, facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour natural gas;

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title problems;

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loss of drilling fluid circulation;

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hydrocarbon or oilfield chemical spills;

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fires, blowouts, surface craterings and explosions;

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surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids;

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delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements; and

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adverse weather conditions and natural disasters.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition and results of operations may be adversely affected. If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our business, financial condition, results of operations and cash flows.

Expenses not covered by our insurance could have a material adverse effect on our financial position and results of operations.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, all of which could cause substantial financial losses. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The location of any properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of potential damages resulting from these risks. The occurrence of any of these or other similar events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension or disruption of operations, substantial revenue losses and repairs to resume operations.

We maintain insurance coverage against potential losses that we believe is customary in the industry. However, insurance against all operational risk is not available to us. These insurance policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A liability, claim or other loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash flows.

The production from our Wyoming Bairoil properties could be adversely affected by the cessation or interruption of the supply of CO₂ to those properties.

We inject water and CO₂ into formations on substantially all of the Wyoming Bairoil properties to increase production of oil and natural gas. The additional production and reserves attributable to the use of enhanced recovery methods are inherently difficult to predict. If we are unable to produce oil and gas by injecting CO₂ in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected. Additionally, our ability to utilize CO₂ to enhance production is subject to our ability to obtain sufficient quantities of CO₂. If, under our CO₂ supply contracts, the supplier is unable to deliver its contractually required quantities of CO₂ to us, or if our ability to access adequate supplies is impeded, then we may not have sufficient CO₂ to produce oil and natural gas in the manner or to the extent that we anticipate, and our future oil and gas production volumes will be negatively impacted.

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

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further exploit and develop our reserves.

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

We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. We cannot predict in advance of drilling, testing and analysis of data whether any particular drilling location will yield production in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Our ability to drill, recomplete and develop locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure and lease expirations. Because of these uncertainties, we cannot be certain of the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition, results of operations and cash flows.

Part of our strategy involves using horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

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landing our wellbore in the desired drilling zone;

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staying in the desired drilling zone while drilling horizontally through the formation;

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running our casing the entire length of the wellbore; and

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being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

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the ability to fracture stimulate the target reservoir formation as planned, including the planned number of stages;

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the ability to run tools the entire length of the wellbore during completion operations; and

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical, which could have a material adverse impact on our financial condition, results of operations and cash flows.

SEC rules could limit our ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and will likely continue to limit our ability to book additional PUDs as we pursue our drilling program, especially in a time of depressed commodity prices. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.

Our industry is cyclical, and historically there have been periodic shortages of rigs, equipment, supplies and crew. Sustained declines in oil and natural gas prices may reduce the number of service providers for such rigs, equipment, supplies and crews, contributing to or resulting in shortages. Alternatively, during periods of higher oil and natural gas prices, the demand for rigs, equipment, supplies and crews is increased and can lead to shortages of, and increasing costs for, development equipment, supplies, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict the Company’s ability to drill the wells and conduct the operations that it currently has planned relating to the fields where our properties are located. In addition, some of our operations require supply materials for production, such as CO₂, which could become subject to shortages and increased costs. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and impact our development plan, which would thus affect our financial conduction, results of operations and our cash flows.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Development and production of oil and natural gas in offshore waters has inherent and historically higher risk than similar activities onshore.

Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than our other oil and natural gas activities. We are vulnerable to the risks associated with operating offshore California, including risks relating to:

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impacts of climate change and natural disasters such as earthquakes, tidal waves, mudslides, fires and floods;

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oil field service costs and availability;

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compliance with environmental and other laws and regulations;

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remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and

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failure of equipment or facilities.

In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our offshore operations are conducted in environmentally sensitive areas, including areas with significant residential populations and public and commercial infrastructure. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of remediating a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

Adverse developments in our operating areas could adversely affect our business, financial condition, results of operations and cash flows.

Our properties are located in the Rockies, federal waters offshore Southern California, East Texas / North Louisiana, Oklahoma and South Texas. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, could adversely affect our business, financial condition, results of operations and cash flows.

We are dependent upon a small number of significant customers for a substantial portion of our production sales. The loss of those customers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition and results of operations.

We had three customers that each accounted for 10% or more of total reported revenues for the year ended December 31, 2019. The loss of these customers or any significant customer, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. Also, if any significant customer reduces the volume it purchases from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, and our revenues and cash flows could decline. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production. See “Item 1. Business — Operations — Marketing and Major Customers.”

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

We are subject to credit risk due to concentration of our oil and natural gas receivables. The inability or failure of our significant customers, or any purchasers of our production, to meet their payment obligations to us or their insolvency or liquidation could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and cash flows.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors and other counterparties. Some of our vendors and other counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors and other counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’ and other counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors and/or counterparties could adversely affect our business, financial condition, results of operations and cash flows.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be unable to compete effectively with larger companies.

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis and many of our competitors have access to capital at a lower cost than that available to us. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition, results of operations and cash flows.

Our business relies on certain key personnel.

Our management believes that our continued success will depend to a significant extent upon the efforts and abilities of certain of our key personnel. The loss of the services of any of these key personnel could have a material adverse effect on our business. We do not maintain “key man” life insurance on any of our officers or other employees.

Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. For example, our ability to produce and sell oil from the Beta properties will depend on the availability of the pipeline infrastructure between platforms as well as the San Pedro Bay Pipeline for delivery of that oil to shore, and any unavailability of that pipeline infrastructure or pipeline could cause us to shut in all or a portion of the production from the Beta properties for the length of such unavailability. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business, financial condition, results of operations and cash flows.

We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.

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

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for and the development, production and transportation of, oil and natural gas. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. In addition, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Further, the Mineral Leasing Act of 1920, as amended (the “Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. It is possible that our stockholders may be citizens of foreign countries who do not own their stock in a U.S. corporation, or that even if such stock are held through a U.S. corporation, their country of citizenship may be determined to be non-reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the more significant laws and regulations that affect us.

Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs, could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. In addition, the EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, almost one-half of the states have taken legal measures to reduce emissions of GHGs, including through the planned development of GHG emission inventories and/or regional GHGs cap and trade programs. In addition, on an international level, the United States was one of 175 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emission reduction goals beginning in 2020. However, on June 1, 2017, President Trump announced that the United States will withdraw from the Paris Agreement, the withdrawal was initiated in November 2019 and is expected to be completed in November 2020. Various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations — Regulation of “Greenhouse Gas” Emissions for a description of the climate change laws and regulations that affect us.

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.

The ESA and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. The listing of species in areas where we operate or, alternatively, entry into certain range-wide conservation planning agreements could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely for gathering and transportation services could impact the availability of those services. Any potential impact to the availability of gathering and transportation services could impact our ability to market and sell our production, which could have a material adverse effect on our business, financial condition and results of operations. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely for gathering and transportation services.

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the CFTC, the SEC, and federal regulators of financial institutions (the “Prudential Regulators”), adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.

Although some of the rules necessary to implement the Dodd-Frank Act have not been finalized, the CFTC, the SEC and the Prudential Regulators have issued a large number of rules, including a rule, which we refer to as the “Clearing Rule,” requiring clearing of certain hedges, or swaps (currently, only certain interest rate and credit default swaps, which we do not presently have), a rule establishing an “end user” exception to the Clearing Rule, referred to herein as the “End User Exception,” a rule, which we refer to as the “Margin Rule,” setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the “Non-Financial End User Exception,” and a rule, subsequently vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further proceedings, imposing position limits. Since the court remand, the CFTC has proposed and withdrawn multiple versions of this rule, issuing its latest proposal in January 2020 (“January 2020 Proposal”). The January 2020 Proposal, which remains pending and subject to public comment and subsequent revision by the CFTC, provides an exemption from the position limits for swaps that constitute “bona fide hedging positions” within the definition of such term under the January 2020 Proposal. Consequently, the impact of final regulations on the Company and its counterparties remains uncertain.

We currently qualify for the End User Exception and will utilize it if the Clearing Rule is expanded to cover swaps in which we participate; we currently qualify for the Non-Financial End User Exception and will not be required to post margin under the Margin Rule, and our existing and anticipated hedging positions likely constitute “bona fide hedging positions” under the January 2020 Proposal and we intend to do the filing, recordkeeping and reporting necessary to utilize the bona fide hedging position exemption under the January 2020 Proposal if and when it becomes effective, so we do not expect to be directly affected by any of these rules implementing the Dodd-Frank Act. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (including laws and regulations giving European Union financial authorities the power to write down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts), which we refer to collectively as “Foreign Regulations” which may apply to our transactions with counterparties subject to such Foreign Regulations. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the January 2020 Proposal is ultimately finalized, could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations and Foreign Regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water and the disposal of waste, including produced water and drilling fluids. Restrictions on the ability to obtain water or dispose of waste may impact our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our development and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The Clean Water Act imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into “waters of the United States.” Permits must be obtained to discharge pollutants to such waters and to conduct construction activities in such waters, which include certain wetlands. The Clean Water Act and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells, and the disposal and recycling of produced water, drilling fluids, and other wastes, may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In some jurisdictions, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity or resulted in stricter regulatory requirements relating to the location and operation of underground injection wells. For example, we conduct oil and gas drilling and production operations in the Mississippian Lime formation in Oklahoma, a high-water play, which requires us to dispose of large volumes of saltwater generated as part of our operations. In 2015, the Oklahoma Geological Survey attributed an increase in seismic activity in Oklahoma to saltwater disposal wells in the Arbuckle formation. Around the same time, the OCC, whose Oil and Gas Conservation Division regulates oil and gas operations in Oklahoma, began issuing regulations targeting saltwater disposal activities in certain areas of interest within the Arbuckle formation. The regulations include operational requirements (i.e., mechanical integrity testing of wells permitted for disposal of 20,000 or more barrels of water per day, daily monitoring and recording of well pressure and discharge volume), as well as orders to shut-in wells, reduce well depths, or decrease disposal volumes. Under these regulations, in 2016 and 2017, the OCC ordered us to limit the volume of saltwater disposed of in saltwater disposal wells in the Arbuckle formation and established caps for ten of our saltwater disposal wells in February 2017. To ensure that we had an adequate number of wells for disposal, we secured permits for additional saltwater disposal wells outside of the Arbuckle formation. We timely satisfied all OCC saltwater disposal requirements, while maintaining our production base without any negative material impact. However, any additional orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations — Water Discharges and Other Waste Discharges & Spills” and “— Hydraulic Fracturing” for additional description of the laws and regulations relating to the discharge of water and other wastes and hydraulic fracturing that affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic fracturing techniques in our drilling and completion programs. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. See “Item 1. Business — Environmental, Health and Safety Matters and Regulations — Hydraulic Fracturing” for a description of the federal and state legislative and regulatory initiatives relating to hydraulic fracturing that affect us.

If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of prohibitions, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes further regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

The cost of decommissioning is uncertain.

We are required to maintain reserve funds to provide for the payment of decommissioning costs associated with the Beta properties. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.

Our business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

As a producer of natural gas and oil, we face from time to time various security threats, including cyber-security threats, to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries and pipelines. These security threats subject our operations to increased risks that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. If any security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations and cash flows.

Damage to our reputation could damage our business.

Our reputation is a critical factor in our relationships with employees, investors, customers and suppliers. If we fail to address, or appear to fail to address, issues that give rise to reputational risk, including those described throughout this “Risk Factors” section, we could significantly harm our reputation. Our reputation may also be damaged by how we respond to corporate crises. Corporate crises can arise from catastrophic events as well as from incidents involving unethical behavior or misconduct; allegations of legal noncompliance; internal control failures; corporate governance issues; data breaches; workplace safety incidents; environmental incidents; media statements; the conduct of our suppliers or representatives; and other issues or incidents that, whether actual or perceived, result in adverse publicity. If we fail to respond quickly and effectively to address such crises, the ensuing negative public reaction could significantly harm our reputation and could lead to increases in litigation claims and asserted damages or subject us to regulatory actions or restrictions.

Damage to our reputation could negatively affect the demand for our services and consequently, have a material adverse effect on our business, financial condition, and results of operations. It could also reduce investor confidence in us, adversely affecting our stock price. Moreover, repairing our reputation may be difficult, time-consuming and expensive.

Changes in U.S. federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition.

The Tax Cuts and Jobs Act (the “Tax Act”), which was signed into law in December 2017, may affect our cash flows, results of operations and financial condition. Among other items, the Tax Act repealed the deduction for certain U.S. production activities and provided for a new limitation on the deduction for interest expense. Given the scope of the Tax Act and the potential interdependency of its changes, it is difficult at this time to assess whether the overall effect of the Tax Act will be cumulatively positive or negative for our earnings and cash flow, but such changes may adversely impact our financial results.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged by the Tax Act, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. It is unclear whether any of the foregoing or similar proposals will be considered and enacted as part of future tax reform legislation and if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development and any such change could have an adverse effect on the Company’s financial position, results of operations and cash flows.

Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.

As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.

Risks Relating to Our Common Stock

The price and trading volume of our common stock may fluctuate significantly.

The market price of our common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. Volatility in the market price of our common stock may prevent you from being able to sell your shares at or above the price at which you were granted your shares of common stock or above the price you paid to acquire your shares of common stock. The market price for our common stock could fluctuate significantly for various reasons, including:

•

our new capital structure as a result of the transactions contemplated by the Plan;

•

our limited trading history subsequent to our emergence from the Chapter 11 Cases;

•

our limited trading volume;

•

the lack of comparable historical financial information due to our adoption of fresh start accounting;

•

actual or anticipated variations in our operating results and cash flow;

•

the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets; and

•

business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

The declaration of dividends on our common stock is within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends in the future or at levels anticipated by our stockholders.

On August 6, 2019, our board of directors initiated a quarterly dividend policy on shares of our common stock payable quarterly beginning with the third quarter of 2019. The decision to pay dividends, however, is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Information regarding our properties is contained in “Item 1. Business — Our Areas of Operation” and “—Our Oil and Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” contained herein.

ITEM 3.

LEGAL PROCEEDINGS

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. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows. No amounts have been accrued at December 31, 2019.

For additional information regarding legal proceedings, see Note 18, “Commitments and Contingencies — Litigation and Environmental” of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report, which is incorporated herein by reference.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock is listed on the New York Stock Exchange (the “NYSE”) under the trading symbol “AMPY” and has been trading since August 7, 2019. Prior to such date, Midstates’ common stock was traded on the NYSE under the trading symbol “MPO” and Legacy Amplify’s common stock was quoted on the OTCQX U.S. Premier marketplace under the trading symbol “AMPY.”

As of February 28, 2020, we had 37,565,610 shares of our common stock outstanding. As of February 28, 2020, we had twenty-five record holders of our common stock, based on information provided by our transfer agent.

Dividends Policy

On November 5, 2019 and on August 6, 2019, our board of directors approved a recurring quarterly dividend policy of $0.20 per share. The Company will evaluate the payment of future quarterly dividends, subject to approval by Amplify’s board of directors.

Securities Authorized for Issuance Under Equity Compensation Plan

See the information incorporated by reference in “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” for information regarding shares of our common stock authorized for issuance under our stock compensation plans, which information is incorporated herein by reference.

Stock Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be filed with the SEC, such information shall not be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.

The performance graph below shows the cumulative total return to our common stockholders from the date our common stock began trading on the NYSE through December 31, 2019, as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P”) for the same period of time. The comparison was prepared on the following assumptions:

•

$100 was invested in our common stock at its opening price of $19.00 per share and invested in the S&P 500 and the S&P O&G E&P on October 24, 2016 at the closing price on such date; and

•

Dividends, if any, are reinvested.

Issuer Purchases of Equity Securities

The following sets forth information with respect to the Company’s repurchases of shares of its common stock during the fourth quarter of 2019.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (1)
							(In thousands)
Common Shares Repurchased (1)
October 1, 2019 - October 31, 2019		9,679	$	6.14		—	n/a
November 1, 2019 - November 30, 2019		—	$	—		—	n/a
December 1, 2019 -December 31, 2019		2,272	$	5.30		—	n/a

(1)

Common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. The Company repurchased the remaining vesting shares on the vesting date at current market price. See Note 14, “Equity-based Awards” of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report, which is incorporated herein by reference.

ITEM 6.

SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

Basis of Presentation. The selected financial data as of and for the years ended December 31, 2019 and 2018, the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and for the years ended December 31, 2016 and 2015 have been derived from our consolidated financial statements, Legacy Amplify consolidated financial statements, the Predecessor consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource Development Corp. in February 2015 for periods after common control commenced through the date of acquisition. The combined selected financial data of the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor operated those assets separately during those periods.

Comparability of the information reflected in selected financial data. The comparability of the results of operations among the periods presented below is impacted by the following acquisitions and divestitures:

•

The acquisition of the remaining interest in the Beta properties from a third party in November 2015 for approximately $94.6 million;

•

The sale of assets located in the Permian Basin in June 2016 for approximately $36.7 million;

•

The sale of assets located in Colorado and Wyoming in July 2016 for approximately $16.4 million;

•

The sale of non-core assets located in South Texas in May 2018 for approximately $17.1 million; and

•

The Merger between Legacy Amplify and Midstates in August 2019.

In addition, the comparability of the results of operations among the periods presented below is impacted by the application of fresh start accounting upon the Legacy Amplify’s emergence from bankruptcy. The Company’s Consolidated Financial Statements are separated into two distinct periods, the period before the Effective Date (labeled Predecessor), and the period after that date (labeled Successor), to indicate the application of different basis of accounting between the periods presented.

As a result of the factors listed above, the combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

				Successor						Predecessor
							Period from
	For the			For the			May 5, 2017			Period from			For the			For the
	Year Ended			Year Ended			through			January 1,			Year Ended			Year Ended
	December 31,			December 31,			December 31,			2017 through			December 31,			December 31,
($ in thousands, except per share/unit data)	2019			2018			2017			May 4, 2017			2016			2015
Statement of Operations Data:
Revenues:
Oil & natural gas sales	$	274,607		$	339,840		$	205,176		$	108,970		$	284,051		$	355,422
Pipeline tariff income and other		968			304			303			231			529			2,725
Total revenues		275,575			340,144			205,479			109,201			284,580			358,147

Costs and expenses:
Lease operating expense		123,918			114,405			74,547			35,568			126,175			168,199
Gathering, processing and transportation		18,475			23,231			18,652			10,772			34,979			34,939
Exploration		51			3,045			32			21			981			2,317
Taxes other than income		18,668			20,364			11,101			5,187			15,540			25,828
Depreciation, depletion and amortization		55,843			52,334			35,979			37,717			171,629			195,814
Impairment expense		2,246			—			—			—			183,437			616,784
General and administrative expense		55,288			43,129			29,506			31,606			63,280			56,671
Accretion of asset retirement obligations		5,559			5,711			4,384			3,407			10,231			7,125
(Gain) loss on commodity derivative instruments		6,700			(8,155	)		31,609			(23,076	)		117,105			(462,890	)
Gain (loss) on sale of properties		—			3,614			—			—			(2,754	)		(2,998	)
Other, net		798			943			485			36			516			(665	)
Total costs and expenses		287,546			258,621			206,295			101,238			721,119			641,124
Operating income (loss)		(11,971	)		81,523			(816	)		7,963			(436,539	)		(282,977	)
Other income (expense):
Interest expense, net		(16,855	)		(21,923	)		(15,936	)		(10,243	)		(146,031	)		(115,154	)
Other income (expense)		(1,117	)		190			16,981			8			8			43
Loss on lease		(4,247	)		—			—			—			—			—
Gain (loss) on extinguishment on debt		—			(3,034	)		—			—			42,337			422
Total other income (expense)		(22,219	)		(24,767	)		1,045			(10,235	)		(103,686	)		(114,689	)
Income (loss) before reorganization items, net and income taxes		(34,190	)		56,756			229			(2,272	)		(540,225	)		(397,666	)
Reorganization items, net		(1,057	)		(2,147	)		(1,119	)		(88,774	)		—			—
Income tax benefit (expense)		50			—			2,176			91			(173	)		2,175
Net income (loss)		(35,197	)		54,609			1,286			(90,955	)		(540,398	)		(395,491	)
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—			386
Net income (loss) attributable to Successor/Predecessor	$	(35,197	)	$	54,609		$	1,286		$	(90,955	)	$	(540,398	)	$	(395,877	)

Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor	$	(35,197	)	$	54,609		$	1,286		$	(90,955	)	$	(540,398	)	$	(395,877	)
Net (income) loss allocated to previous owners		—			—			—			—			—			2,268
Net (income) loss allocated to Predecessor's general partner		—			—			—			—			168			327
Net (income) loss allocated to NGP IDRs		—			—			—			—			—			(83	)
Net (income) allocated to participating restricted stockholders		—			(2,426	)		(35	)		—			—			—
Net income (loss) available to common stockholders/limited partners	$	(35,197	)	$	52,183		$	1,251		$	(90,955	)	$	(540,230	)	$	(393,365	)

Earnings per share/unit:
Basic earnings per share/unit	$	(1.20	)	$	2.09		$	0.05		$	(1.09	)	$	(6.48	)	$	(4.71	)
Diluted earnings per share/unit	$	(1.20	)	$	2.09		$	0.05		$	(1.09	)	$	(6.48	)	$	(4.71	)

Predecessor's cash distributions declared per unit	n/a			n/a			n/a			n/a			$	0.16		$	1.95

Cash Flow Data:
Net cash flow provided by operating activities	$	47,283		$	141,781		$	94,642		$	125,498		$	408,626		$	216,751
Net cash provided by (used in) investing activities		35,315			23,666			(53,357	)		(6,496	)		(16,442	)		(337,569	)
Net cash provided by (used in) financing activities		(132,302	)		(121,810	)		(62,594	)		106,674			(377,410	)		120,447

Balance Sheet Data:
Working capital (deficit)	$	(8,501	)	$	55,179		$	35,948		$	59,527		$	(1,581,193	)	$	246,778
Total assets		877,539			836,843			917,464			981,427			1,973,254			2,906,003
Current portion of long-term debt ⁽¹⁾		—			—			—			—			1,622,904			—
Long-term debt ⁽¹⁾		285,000			294,000			376,000			430,000			—			2,000,579
Total equity		434,207			416,558			393,933			390,140			99,489			645,492

(1)

Due to the existing and anticipated financial covenant violations at December 31, 2016, the borrowings under the Predecessor’s revolving credit facility and the Predecessor’s 7.625% senior notes due May 2021 and 6.875% senior notes due August 2022 were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2019, 2018 and 2017, respectively.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” contained herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I, Item 1A. of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of this annual report.

Overview

We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on the reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas/North Louisiana and South Texas. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs.

•

Our total estimated proved reserves were approximately 163.0 MMBoe, of which approximately 43% were oil and 80% were classified as proved developed reserves;

•

We produced from 2,643 gross (1,567 net) producing wells across our properties, with an average working interest of 59%, and the Company is the operator of record of the properties containing 93% of our total estimated proved reserves; and

•

Our average net production for the three months ended December 31, 2019 was 29.9 MBoe/d, implying a reserve-to-production ratio of approximately 15 years.

Recent Developments

Merger

On August 6, 2019, Midstates completed its business combination with Legacy Amplify in accordance with the terms of the Merger Agreement, by and among Midstates, Legacy Amplify and Merger Sub. Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates, and immediately following the Merger, Legacy Amplify merged with and into LLC Sub, with LLC Sub surviving as a wholly owned subsidiary of Midstates. At the effective time of the Merger, each share of Legacy Amplify common stock issued and outstanding immediately prior to the effective time (other than excluded shares) were cancelled and converted into the right to receive 0.933 shares of Midstates common stock, par value $0.01 per share. On the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.” and LLC Sub changed its name to “Amplify Energy Holdings LLC. Following the closing of the Merger, Legacy Amplify stockholders and Midstates stockholders each owned approximately 50% of the outstanding stock of the Company and the Company continues to operate under the Amplify brand.

Borrowing Base Redetermination

On November 8, 2019, as part of the Company fall 2019 semiannual borrowing base redetermination, the borrowing base and lender commitments under the Company’s credit agreement among wholly owned subsidiaries of the Company, Bank of Montreal, as administrative agent, and other lenders party thereto (as amended from time to time, the “Revolving Credit Facility”) were decreased from $530.0 million to $450.0 million, with the next such redetermination scheduled for spring 2020. The Revolving Credit Facility is a reserve-based revolving credit facility with a maturity date of November 2, 2023, and semiannual borrowing base redeterminations.

Departure of Certain Officers

Predecessor and Successor Reporting

As a result of the application of fresh start accounting upon the emergence from bankruptcy, the Legacy Amplify’s Consolidated Financial Statements and certain note presentations are separated into two distinct periods, the period before the Effective Date (labeled Predecessor) and the period after that date (labeled Successor), to indicate the application of different basis of accounting between the periods presented. Despite this separate presentation, there was continuity of the Legacy Amplify operations.

See Note 3 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information related to our adoption of fresh start accounting.

Business Environment and Operational Focus

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production; (iii) cash settlements on our commodity derivatives; (iv) lease operating expense; (v) gathering, processing and transportation; (vi) general and administrative expense; and (vii) Adjusted EBITDA.

Production Volumes

Production volumes directly impact our results of operations. For more information about our volumes, see “— Results of Operations” below.

Realized Prices on the Sale of Oil and Natural Gas

We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, realized prices are heavily influenced by product quality and location relative to consuming and refining markets.

Natural Gas. The NYMEX-Henry Hub future price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas can differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO₂ and other inert content by volume. Natural gas with a high Btu content (“wet” natural gas) sells at a premium to natural gas with low Btu content (“dry” natural gas) because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO₂ content sells at a premium to natural gas with high sulfur and CO₂ content because of the added cost required to separate the sulfur and CO₂ from the natural gas to render it marketable. Wet natural gas may be processed in third-party natural gas plants, where residue natural gas as well as NGLs are recovered and sold. At the wellhead, our natural gas production typically has an average energy content greater than 1,000 Btu. The dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the produced natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Historically, these index prices have generally been at a discount to NYMEX-Henry Hub natural gas prices.

Oil. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The ICE Brent futures price is a widely used global price benchmark for oil. The actual prices realized from the sale of oil can differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s American Petroleum Institute (“API”) gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil).

Location differentials result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential).

The oil produced from our onshore properties is a combination of sweet and sour oil, varying by location. This oil is typically sold at the NYMEX-WTI price, adjusted for quality and transportation differential, depending primarily on location and purchaser. The oil produced from our Beta properties is heavy and sour oil. Oil produced from our Beta properties is currently sold based on refiners’ posted prices for California Midway-Sunset deliveries in Southern California, adjusted primarily for quality and a negotiated market differential.

Price Volatility. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. The following table shows the low and high commodity future index prices for the periods indicated:

	High		Low
For the Year Ended December 31, 2019:
NYMEX-WTI oil future price range per Bbl	$	66.30	$	46.54
NYMEX-Henry Hub natural gas future price range per MMBtu	$	4.25	$	1.82
ICE Brent oil future price range per Bbl	$	74.57	$	54.91

For the Five Years Ended December 31, 2019:
NYMEX-WTI oil future price range per Bbl	$	76.41	$	26.21
NYMEX-Henry Hub natural gas future price range per MMBtu	$	6.88	$	1.49
ICE Brent oil future price range per Bbl	$	86.29	$	27.88

Commodity Derivative Contracts. Our hedging activities are intended to support oil, natural gas and NGL prices at targeted levels and to manage our exposure to commodity price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 25% - 50% of our estimated production from proved developed producing reserves over a one-to-three-year period at any given point of time to satisfy the hedging covenants in our Revolving Credit Facility and pursuant to our internal policies. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Principal Components of Cost Structure

•

Lease operating expense. These are the day to day costs incurred to maintain production of our natural gas, NGLs and oil. Such costs include utilities, direct labor, water injection and disposal, the cost of CO₂ injection, chemicals, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services and activities performed during a specific period.

•

Gathering, processing and transportation. These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil production.

•

Exploration expense. These are geological and geophysical costs and include certain seismic costs, costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts. Exploration expense also include rig contract termination fees.

•

Taxes other than income. These consist of production, ad valorem and franchise taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take advantage of credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties. Franchise taxes are privilege taxes levied by states that are imposed on companies, including limited liability companies and partnerships, which gives the businesses the right to be chartered or operate within that state.

•

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop oil and natural gas properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.

•

Impairment expense. Proved properties are impaired whenever the net carrying value of the properties exceed their estimated undiscounted future cash flows. Unproved properties are impaired based on time or geologic factors.

•

General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, audit and other professional fees and legal compliance expenses.

•

Accretion expense. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value.

•

Interest expense. Historically, we financed a portion of our working capital requirements, capital development and acquisitions with borrowings under our Revolving Credit Facility, our Emergence Credit Facility, our Predecessor’s revolving credit facility and the Predecessor’s senior note issuances. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense.

•

Income tax expense. We are a corporation subject to federal and certain state income taxes. Our Predecessor was organized as a pass-through entity for federal and most state income tax purposes. During the period from January 1, 2017 through May 4, 2017, certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes. We are subject to the Texas margin tax for activities in the State of Texas.

Outlook

Based on our current plans, our capital expenditure program for the full year 2020 is expected to be approximately $40.0 million to $52.0 million. The charts below detail the allocation of capital across our asset base and by investment type based on the midpoint of our 2020 capital expenditure range. The amounts noted below are in millions:

As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices and other factors. We anticipate funding our 2020 capital program from internally generated cash flow. Borrowings under our Revolving Credit Facility and/or debt or equity financings may provide incremental financial flexibility.

Critical Accounting Policies and Estimates

Fresh Start Accounting

Upon the Effective Date, Legacy Amplify adopted fresh start accounting as required by GAAP. Legacy Amplify met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of Legacy Amplify and (ii) the reorganization value of Legacy Amplify assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims. Fresh start accounting involved a comprehensive valuation process in which we determined the fair value of all of Legacy Amplify assets and liabilities on the Effective Date. See Note 3 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information related to Legacy Amplify adoption of fresh start accounting.

Use of Estimates

The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs attributable to unproved locations are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Rockies and California assets, are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.

Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the Consolidated Financial Statements are estimated in accordance with the rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged CG&A, our independent reserve engineers, to prepare our reserves estimates for all of our proved reserves (by volume) at December 31, 2019.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production or drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, collars and puts) are used to reduce the impact of natural gas and oil price fluctuations. Every derivative instrument is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings as we have not elected hedge accounting for any of our derivative positions.

Business Combinations

Accounting for the acquisition of a business requires the identifiable assets and liabilities acquired to be recorded at fair value. The most significant assumptions in a business combination include those used to estimate the fair value of the oil and gas properties acquired. The fair value of proved natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant assumptions including commodity prices; projections of estimated quantities of reserves; projections of future rates of production; timing and amount of future development and operating costs; projected reserve recovery factors; and a weighted average cost of capital.

The Company utilizes a market approach to estimate the fair value of unproved properties acquired in a business combination which requires the Company to use judgment in considering the value per undeveloped acre in recent comparable transactions to estimate the value of unproved properties.

The Company believes that the accounting estimates related to business combinations are “critical accounting estimates” because the Company must, in determining the fair value of assets acquired, make assumptions about future commodity prices; projections of estimated quantities of reserves; projections of future rates of production; projections regarding the timing and amount of future development and operating costs; and projections of reserve recovery factors, per acre values of undeveloped property, replacement cost of and future cash flows from midstream assets, cash flow from customer relationships and non-compete agreements and the pre and post modification value of stock based awards. Different assumptions may result in materially different values for these assets which would impact the Company’s financial position and future results of operations.

Results of Operations

The results of operations for the years ended December 31, 2019 and 2018, the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017, have been derived from our consolidated financial statements.

Factors Affecting the Comparability of the Historical Financial Results

The comparability of the results of operations among the periods presented is impacted by the following significant transactions:

•

The South Texas Divestiture in May 2018 for approximately $17.1 million; and

•

The Merger between Legacy Amplify and Midstates in August 2019.

As a result of the factors listed above, the historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

	For the			For the
	Year Ended			Year Ended
	December 31,			December 31,
	2019			2018
	($ In thousands)
Oil and natural gas sales	$	274,607		$	339,840
Lease operating expense		123,918			114,405
Gathering, processing and transportation		18,475			23,231
Exploration expense		51			3,045
Taxes other than income		18,668			20,364
Depreciation, depletion and amortization		55,843			52,334
Impairment expense		2,246			—
General and administrative expense		55,288			43,129
Accretion of asset retirement obligations		5,559			5,711
(Gain) loss on commodity derivative instruments		6,700			(8,155	)
(Gain) loss on sale of properties		—			3,614
Interest expense, net		(16,855	)		(21,923	)
Other income (expense)		(1,117	)		190
Loss on lease		(4,247	)		—
Gain (loss) on extinguishment of debt		—			(3,034	)
Reorganization items, net		(1,057	)		(2,147	)
Income tax benefit (expense)		50			—
Net income (loss)		(35,197	)		54,609

Oil and natural gas revenue:
Oil sales	$	192,944		$	209,066
NGL sales		22,347			42,463
Natural gas sales		59,316			88,311
Total oil and natural gas revenue	$	274,607		$	339,840

Production volumes:
Oil (MBbls)		3,498			3,335
NGLs (MBbls)		1,343			1,496
Natural gas (MMcf)		26,489			29,176
Total (MBoe)		9,256			9,694
Average net production (MBoe/d)		25.4			26.6

Average sales price:
Oil (per Bbl)	$	55.16		$	62.68
NGL (per Bbl)		16.64			28.38
Natural gas (per Mcf)		2.24			3.03
Total (per Boe)	$	29.67		$	35.06

Average unit costs per Boe:
Lease operating expense	$	13.39		$	11.80
Gathering, processing and transportation		2.00			2.40
Taxes other than income		2.02			2.10
General and administrative expense		5.97			4.45
Depletion, depreciation and amortization		6.03			5.40

For the year ended December 31, 2019 compared to the year ended December 31, 2018

Net loss of $35.2 million and net income of $54.6 million was recorded for the year ended December 31, 2019 and 2018, respectively.

Oil, natural gas and NGL revenues were $274.6 million and $339.8 million for the year ended December 31, 2019 and 2018, respectively. Average net production volumes were approximately 25.4 MBoe/d and 26.6 MBoe/d for the year ended December 31, 2019 and 2018, respectively. The change in production volumes was primarily related to decreases in drilling activities partially offset by the Merger of Midstates. The average realized sales price was $29.67 per Boe and $35.06 per Boe for the year ended December 31, 2019 and 2018, respectively. The change in the average realized sales price was primarily due to lower production.

Lease operating expense was $123.9 million and $114.4 million for the year ended December 31, 2019 and 2018, respectively. The change in lease operating expense was the result of increased workover activity and the Merger with Midstates. On a per Boe basis, lease operating expense was $13.39 and $11.80 for the year ended December 31, 2019 and 2018, respectively. The change in lease operating expense on a per Boe basis was primarily related to increased workover activity and lower production.

Gathering, processing and transportation expenses were $18.5 million and $23.2 million for the year ended December 31, 2019 and 2018, respectively. The change in gathering, processing and transportation expenses was primarily due to lower production. On a per Boe basis, gathering, processing and transportation expenses were $2.00 and $2.40 for the year ended December 31, 2019 and 2018, respectively.

Taxes other than income was $18.7 million and $20.4 million for the year ended December 31, 2019 and 2018, respectively. On a per Boe basis, taxes other than income were $2.02 and $2.10 for the year ended December 31, 2019 and 2018, respectively. The change in taxes other than income on a per Boe basis was primarily due to a decrease in commodity prices.

DD&A expense was $55.8 million and $52.3 million for the year ended December 31, 2019 and 2018, respectively. The change in DD&A expense was primarily due to the Merger with Midstates which closed on August 6, 2019.

Impairment expense was $2.2 million for the year ended December 31, 2019 related to certain unproved leasehold costs in Oklahoma. This was primarily due to changes in development plans in the areas of Alfalfa, Major and Woods Counties in Oklahoma. No impairment expense was recognized for the year ended December 31, 2018.

General and administrative expense was $55.3 million and $43.1 million for the year ended December 31, 2019 and 2018, respectively. General and administrative expense for the year ended December 31, 2019, includes $17.3 million related to acquisition expense and $7.3 million related to severance payments. The Merger acquisition expenses are non-recurring and are not expected to impact future expenses. Non-cash share/unit-based compensation expense was approximately $4.8 million and $4.2 million for the year ended December 31, 2019 and 2018, respectively. General and administrative expense for the year ended December 31, 2018, included $7.5 million in severance payments to certain Legacy Amplify departing executives.

Net losses on commodity derivative instruments of $6.7 million were recognized for the year ended December 31, 2019, consisting of $10.9 million decrease in the fair value of open positions offset by $4.2 million of cash settlements received on expired positions. Net gains on commodity derivative instruments of $8.2 million were recognized for the year ended December 31, 2018, consisting of $10.1 million of cash settlements received on expired positions offset by a $1.9 million decrease in the fair value of open positions.

Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

Interest expense, net was $16.9 million and $21.9 million for the year ended December 31, 2019 and 2018, respectively. The change in interest expense is primarily due to a $5.7 million reduction in interest expense due to lower outstanding borrowing for the year ended December 31, 2019. In addition, we had gains of interest rate swaps of approximately $0.2 million. The Company recognized $1.2 million and $2.5 million in amortization and write-off of deferred financing cost for the year ended December 31, 2019 and 2018, respectively.

Average outstanding borrowings under our Revolving Credit Facility were $264.9 million for the year ended December 31, 2019 and $294.0 million for the period from November 2, 2018 through December 31, 2018, respectively. Average outstanding borrowings under our Emergence Credit Facility were $330.4 million for the period from January 1, 2018 through November 1, 2018.

Loss on Lease was $4.2 million for the year ended December 31, 2019, which is related to the Midstates corporate office lease. The office was vacated in mid-November. Due to excess sublease inventory in the local market, a liability has been accrued for rent and other operating expenses based upon the term and provisions of the lease.

Reorganization items, net represents costs and income directly associated with Legacy Amplify’s Chapter 11 proceedings since the Petition Date, such as advisor and professional fees. The Company incurred $1.1 million and $2.1 million of reorganization items, net for the year ended December 31, 2019 and 2018, respectively. See Note 3 of the Notes to the Consolidated Financial Statements under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.

For the year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017

Information related to the comparison of our operating results between the years 2018 and 2017 is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2018 Form 10-K filed with the SEC and is incorporated by reference into this Annual Report on Form 10-K.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash flow from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

•

Interest expense, including gains or losses on interest rate derivative contracts;

•

Income tax expense;

•

DD&A;

•

Impairment of goodwill and long-lived assets (including oil and natural gas properties);

•

Accretion of asset retirement obligations (“AROs”);

•

Loss on commodity derivative instruments;

•

Cash settlements received on expired commodity derivative instruments;

•

Losses on sale of assets and other, net;

•

Share/unit-based compensation expenses;

•

Exploration costs;

•

Acquisition and divestiture related expenses;

•

Amortization of gain associated with terminated commodity derivatives;

•

Restructuring related costs;

•

Reorganization items, net;

•

Severance payments;

•

Bad debt expense; and

•

Other non-routine items that we deem appropriate.

Less:

•

Interest income;

•

Income tax benefit;

•

Gain on extinguishment of debt

•

Gain on expired commodity derivative instruments;

•

Cash settlements paid on expired commodity derivative instruments;

•

Gains on sale of assets and other, net; and

•

Other non-routine items that we deem appropriate.

We are required to comply with certain Adjusted EBITDA-related metrics under our Revolving Credit Facility.

We believe that Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.

Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow, develop existing reserves or acquire additional oil and natural gas properties.

The following tables present our calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.

Calculation of Adjusted EBITDA

				Successor						Predecessor
	For the			For the			Period from			Period from
	Year Ended			Year Ended			May 5, 2017			January 1, 2017
	December 31,			December 31,			through			through
	2019			2018			December 31, 2017			May 4, 2017
	(In thousands)									(In thousands)
Net income (loss)	$	(35,197	)	$	54,609		$	1,286		$	(90,955	)
Interest expense, net		16,855			21,923			15,936			10,243
Gain (loss) on extinguishment of debt		—			3,034			—			—
Income tax expense (benefit)		(50	)		—			(2,176	)		(91	)
DD&A		55,843			52,334			35,979			37,717
Impairment expense		2,246			—			—			—
Accretion of AROs		5,559			5,711			4,384			3,407
(Gains) losses on commodity derivative instruments		6,700			(8,155	)		31,609			(23,076	)
Cash settlements received (paid) on expired commodity derivative instruments		4,157			10,087			30,445			15,895
(Gain) loss on sale of properties		—			3,614			—			—
Acquisition and divestiture related expenses		17,305			205			609			—
Share/Unit-based compensation expense		4,813			4,198			2,516			3,667
Exploration costs		51			3,045			32			16
(Gain) loss on settlement of AROs		403			953			181			36
Restructuring related costs		—			—			—			7,548
Reorganization items, net		1,057			2,147			1,119			88,774
Third-party midstream transaction		—			(105	)		(16,979	)		—
Bad debt expense		301			106			—			—
Severance payments		7,299			7,485			—			—
Non-cash loss on office lease		4,247			—			—			—
Write-off of merger related expenses		1,420			—			—			—
Other		—			—			—			57
Adjusted EBITDA	$	93,009		$	161,191		$	104,941		$	53,238

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

				Successor						Predecessor
	For the			For the			Period from			Period from
	Year Ended			Year Ended			May 5, 2017			January 1, 2017
	December 31,			December 31,			through			through
	2019			2018			December 31, 2017			May 4, 2017
	(In thousands)									(In thousands)
Net cash provided by operating activities	$	47,283		$	141,781		$	94,642		$	125,498
Changes in working capital		(949	)		(14,316	)		10,832			(16,524	)
Interest expense, net		16,855			21,923			15,936			10,243
Gain (loss) on interest rate swaps		224			—			—			—
Cash settlements paid (received) on interest rate derivative instruments		(187	)		—			—			—
Cash settlements received on terminated commodity derivatives		—			—			—			(94,146	)
Amortization and extinguishment of deferred financing fees		(1,174	)		(2,518	)		(2,093	)		—
Acquisition and divestiture related expenses		17,305			205			609			—
Income tax expense (benefit) - current portion		(50	)		—			30			(17	)
Exploration costs		51			3,045			32			16
Plugging and abandonment cost		662			1,720			813			200
Restructuring related costs		—			—			—			7,548
Reorganization items, net		1,057			2,147			1,119			20,420
Severance payments		7,299			7,485			—			—
Third-party midstream transaction		—			(105	)		(16,979	)		—
Non-cash loss on office lease		4,247			—			—			—
Other		386			(176	)		—			—
Adjusted EBITDA	$	93,009		$	161,191		$	104,941		$	53,238

Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our Predecessor’s revolving credit facility, our Emergence Credit Facility or our Revolving Credit Facility, as applicable, and equity and debt capital markets. As we pursue reserve and production growth, we plan to monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our Revolving Credit Facility will provide us with the financial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2020 development activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. We anticipate funding our 2020 capital program from internally generated cash flow. Borrowings under our Revolving Credit Facility and/or debt or equity financings may provide incremental financial flexibility.

Capital Markets. We do not currently anticipate any near-term capital markets activity, but we will continue to evaluate the availability of public debt and equity for funding potential future growth projects and acquisition activity.

Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 25% - 50% of our estimated production from total proved developed producing reserves over a one-to-three-year period at any given point of time to satisfy the hedging covenants in our Revolving Credit Facility and pursuant to our internal policies. We may, however, from time to time, hedge more or less than this approximate amount. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts. For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of December 31, 2019, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could also result in losses.

Capital Expenditures. Our total capital expenditures were approximately $71.6 million for the year ended December 31, 2019, which were primarily related to drilling, capital workovers and capital facilities expenditures located in the Rockies, California and South Texas.

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 decreases 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 December 31, 2019, we had a working capital deficit balance of $8.5 million primarily as the result of (i) an accounts receivable balance of $33.1 million, (ii) prepaid expenses and other current assets balance of $13.2 million and (iii) a current derivative asset balance of $5.9 million less (i) an accrued liabilities balance of $23.4 million, (ii) a revenue payable balance of $29.2 million and (iii) an accounts payable balance of $8.3 million.

Debt Agreements

Revolving Credit Facility. On November 2, 2018, OLLC as borrower, entered into the Revolving Credit Facility (as amended and supplemented to date) with Bank of Montreal, as administrative agent. At December 31, 2019, our borrowing base under our Revolving Credit Facility was subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the available natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. The borrowing base as of December 31, 2019, was $450.0 million.

As of December 31, 2019, we were in compliance with all the financial (current ratio and total leverage ratio) and other covenants associated with our Revolving Credit Facility.

As of December 31, 2019, we had approximately $163.4 million of available borrowings under our Revolving Credit Facility, net of $1.7 million in letters of credit.

For additional information regarding the Revolving Credit Facility, see Note 11 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual 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 years ended December 31, 2019 and 2018, have been derived from our Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.

	For the			For the
	Year Ended			Year Ended
	December 31,			December 31,
	2019			2018
	(In thousands)
Net cash provided by operating activities	$	47,283		$	141,781
Net cash provided by investing activities		35,315			23,666
Net cash used in financing activities		(132,302	)		(121,810	)

For the year ended December 31, 2019 compared to December 31, 2018

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. For year ended December 31, 2019 we are at a net loss position of $35.2 million compared to a net income position of $54.6 million for the year ended December 31, 2018. Net cash provided by operating activities for 2019 included $4.3 million of cash receipts on expired derivative instruments compared to $10.1 million of cash receipts on expired derivative instruments for 2018. For 2019, we had net losses on derivative instruments of $6.7 million compared to net gains of $8.2 million for 2018. Production volumes decreased to 25.4 MBoe/d in 2019 from 26.6 MBoe/d in 2018 and the average realized sales price decreased to $29.67 per Boe in 2019 from $35.06 per Boe in 2018 primarily due to the lower production.

Investing Activities. Net cash used in investing activities was $35.3 million and $23.7 million for the year ended December 31, 2019 and 2018, respectively.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and natural gas properties. Withdrawal of restricted investment was $90.0 million and $62.5 million at December 31, 2019 and 2018, respectively, which related to the Company receiving funds from the trust account (the “Beta Decommissioning Trust Account”). Additions to restricted investments were $0.2 million and $0.5 million for the year ended December 31, 2019 and 2018, respectively. See Note 10 of the Notes to the Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our restricted investments.

During 2019, we used $72.7 million for additions to oil and gas properties partially offset by $19.3 million related to cash acquired from the Merger with Midstates. During 2018, we used $55.4 million for additions to oil and gas properties partially offset by $17.1 million in proceeds from the sale of oil and natural gas properties primarily related to the South Texas Divestiture.

Financing Activities. The Company had net repayments of $9.0 million under the Revolving Credit Facility for the year ended December 31, 2019. The Company had net repayments of $82.0 million under the Emergence Credit Facility and paid $3.5 million in deferred financing costs for the year ended December 31, 2018.

Upon closing of the Merger on August 6, 2019, Midstates’ existing reserve-based revolving credit facility was terminated and all remaining borrowings were repaid by the Company.

For the year ended December 31, 2019, the Company repurchased 4,364,647 shares of common stock at an average price of $6.80 per share for a total cost of approximately $26.2 million under the Share Repurchase Program.

For the year ended December 31, 2019, the Company paid dividends of $15.9 million in aggregate.

For the year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017

Information related to the comparison of our discussion of the cash flows for the year ended December 31, 208 compared to the year ended December 31, 2017, is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” of our 2018 Form 10-K filed with the SEC and is incorporated by reference into this Annual Report on Form 10-K.

Capital Requirements

See “— Outlook” for additional information regarding our capital spending program for 2020.

Contractual Obligations

In the table below, we set forth our contractual obligations as of December 31, 2019. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

			Payment or Settlement due by Period
Contractual Obligation	Total		Less than 1 year		1-3 years		4-5 years		Thereafter
	(In thousands)
Revolving Credit Facility (1)	$	285,000	$	—	$	—	$	285,000	$	—
Estimated interest payments (2)		52,003		13,566		27,132		11,305		—
Asset retirement obligations (3)		65,668		623		—		—		65,045
CO₂ minimum purchase commitment (4)		4,365		4,365		—		—		—
Operating leases (5)		10,516		6,782		2,504		410		820
Midstream services (6)		11,781		3,967		7,534		280		—
Total	$	429,333	$	29,303	$	37,170	$	296,995	$	65,865

(1)

Represents the scheduled future maturities of principal amount outstanding for the periods indicated. Maturities are shown at original maturity dates assuming no acceleration. See Note 11 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for information regarding our Revolving Credit Facility.

(2)

Estimated interest payments are based on the principal amount outstanding under our Revolving Credit Facility at December 31, 2019. In calculating these amounts, we applied the weighted-average interest rate for the year ended December 31, 2019 associated with such debt. See Note 11 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for the weighted-average variable interest rate charged during 2019 under our Revolving Credit Facility. Maturities are shown at original maturity dates assuming no acceleration.

(3)

Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2019 balance sheet. See Note 9 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information regarding our asset retirement obligations.

(4)	Represents a firm agreement to purchase CO₂volumes related to our Bairoil properties in Wyoming.

(5)

Primarily represents leases for office space as well as equipment rentals and offshore Southern California right-of-way use. See Note 18 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for information regarding our operating leases.

(6)	Represents processing fees associated with a minimum volume commitment related to certain of our properties located in Oklahoma and East Texas.

Off–Balance Sheet Arrangements

As of December 31, 2019, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 4 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the prices that we receive for our oil, natural gas and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices we receive. It has been our practice to enter into fixed price swaps and costless collars only with lenders and their affiliates under our Predecessor’s revolving credit facility, our Emergence Credit Facility and our Revolving Credit Facility, as applicable.

Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.

Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, primarily based on NYMEX, or regional quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Collars are typically exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise they expire.

Puts. In a typical put contract, we (as the buyer of the put option) hedge against the potential for lower prices by limiting our exposure and setting a floor price for the hedged commodity. This mitigates downside risk but we retain the upside on commodity prices above the fixed floor price. Puts are typically exercised in cash on a monthly basis only when the reference price is below the floor prices. In addition, puts typically have a cost (or premium) associated with the purchase that will either be settled at the time of purchase or deferred until the period covered by the transaction. These costs will be paid regardless of the commodity price during the hedge period.

The following table summarizes our derivative contracts as of December 31, 2019 and the average prices at which the production will be hedged:

	2020			2021			2022
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)		600,000			487,500			300,000
Weighted-average fixed price	$	2.53		$	2.48		$	2.46

Collar contracts:
Two-way collars
Average monthly volume (MMBtu)		520,000			162,500			—
Weighted-average floor price	$	2.64		$	2.58		$	—
Weighted-average ceiling price	$	2.96		$	2.84		$	—

Three-way collars
Average monthly volume (MMBtu)		76,000			—			—
Weighted-average ceiling price	$	3.45		$	—		$	—
Weighted-average floor price	$	2.65		$	—		$	—
Weighted-average sub-floor price	$	2.15		$	—		$	—

Natural Gas Basis Swaps:
PEPL basis swaps:
Average monthly volume (MMBtu)		600,000			500,000			—
Weighted-average spread	$	(0.46	)	$	(0.40	)	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		213,050			116,250			30,000
Weighted-average fixed price	$	57.28		$	56.05		$	55.32

Collar contracts:
Two-way collars
Average monthly volume (Bbls)		14,300			—			—
Weighted-average floor price	$	55.00		$	—		$	—
Weighted-average ceiling price	$	62.10		$	—		$	—

Three-way collars
Average monthly volume (Bbls)		30,500			—			—
Weighted-average ceiling price	$	65.75		$	—		$	—
Weighted-average floor price	$	50.00		$	—		$	—
Weighted-average sub-floor price	$	40.00		$	—		$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		65,425			22,800			—
Weighted-average fixed price	$	25.20		$	24.25		$	—

The following table summarizes our derivative contracts as of December 31, 2018 and the average prices at which the production was hedged:

	2019		2020
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		1,565,000		—
Weighted-average fixed price	$	2.89	$	—

Collar contracts:
Average Monthly Volume (MMBtu)		—		90,000
Weighted-average floor price	$	—	$	2.60
Weighted-average ceiling price	$	—	$	2.85

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		148,000		—
Weighted-average fixed price	$	53.06	$	—

Collar contracts:
Average Monthly Volume (Bbls)		38,000		14,300
Weighted-average floor price	$	55.00	$	55.00
Weighted-average ceiling price	$	63.85	$	62.10

Purchased put option contracts:
Average Monthly Volume (Bbls)		—		14,300
Weighted-average strike price	$	—	$	55.00

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		72,000		18,200
Weighted-average fixed price	$	29.96	$	28.67

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2019, we had the following interest rate swap open positions:

	2020			2021			2022
Average Monthly Notional (in thousands)	$	125,000		$	125,000		$	75,000
Weighted-average fixed rate		1.612	%		1.612	%		1.281	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

The Company did not have any interest rate swaps at December 31, 2018.

Counterparty and Customer Credit Risk

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Some of the lenders, or certain of their affiliates, under our Revolving Credit Facility are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2019, after taking into effect netting arrangements, we had no counterparty exposure related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $12.6 million against amounts outstanding under our Revolving Credit Facility at December 31, 2019.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this Annual Report and are incorporated herein by reference.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of the Company, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this annual report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of the Company, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon this evaluation, the principal executive officer and principal financial officer of the Company have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2019.

Management’s Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Under the supervision and with the participation of the Company’s management, including the principal executive officer and principal financial officer of the Company, the Company assessed the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this assessment, the Company’s management, including its principal executive and financial officers, concluded that the Company’s internal control over financial reporting was effective as of December 31, 2019 based on the criteria set forth under the COSO Framework.

KPMG LLP, the independent registered public accounting firm who audited the Company’s Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” in this annual report, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, is contained herein under the heading “Report of Independent Registered Public Accounting Firm.”

Changes in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2019 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 annual report.

Report of Independent Registered Public Accounting Firm

The Stockholders and Board of Directors

Amplify Energy Corp.:

Opinion on Internal Control Over Financial Reporting

We have audited Amplify Energy Corp. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related statements of consolidated operations, equity and cash flows for the year ended December 31, 2019, the year ended December 31, 2018, the period May 5, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through May 4, 2017 (Predecessor) and the related notes (collectively, the consolidated financial statements), and our report dated March 5, 2020 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Houston, Texas

March 5, 2020

ITEM 9B.

OTHER INFORMATION

None

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement relating to the 2020 Annual Meeting of Stockholders of Amplify Energy Corp. (the “Proxy Statement”) to be held on May 20, 2020.

The Company’s Code of Business Conduct and Ethics (the “Code of Ethics”) can be found on the Company’s website located at http://investor.amplifyenergy.com/corporate-governance. Any stockholder may request a printed copy of the Code of Ethics by submitting a written request to the Company’s Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.

ITEM 11.

EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference to the Proxy Statement.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item is incorporated herein by reference to the Proxy Statement.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is incorporated herein by reference to the Proxy Statement.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated herein by reference to the Proxy Statement.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

Our Consolidated Financial Statements are included under Part II, “Item 8. Financial Statements and Supplementary Data” of the annual report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” on Page F-1 of this annual report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3) Exhibits

The exhibits listed on the Exhibit Index below are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

Exhibit Index

Exhibit Number		Description

2.1	—	Joint Plan of Reorganization of Memorial Production Partners LP, et al. under Chapter 11 of the Bankruptcy Code, dated as of January 16, 2017 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).

2.2##	—	Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2017).

2.3	—	Agreement and Plan of Merger, dated May 5, 2019, by and among Amplify Energy Corp., Midstates Petroleum Company, Inc. and Midstates Holdings, Inc. (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 6, 2019).

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 Certificate of Incorporation of Midstates Petroleum Company, Inc., dated August 6, 2019 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

3.3	—	Second Amended and Restated Bylaws of Midstates Petroleum Company Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

4.1#	—	Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).

4.2#	—	Form of Phantom Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to Annual Report on Form 10-K (File No. 001-35364) filed on February 24, 2016).

4.3*	—	Description of the Company’s Capital Stock Registered Under Section 12 of the Securities Exchange Act of 1934.

10.1	—	Amplify Energy Corp. Amended and Restated Registration Rights Agreement, dated August 6, 2019, between the Company and certain holders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

10.2	—	Assignment and Assumption Agreement, dated August 6, 2019, by and among Legacy Amplify, Midstates and American Stock Transfer & Trust Company, LLC (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

10.3	—	Warrant Agreement between Legacy Amplify, as Issuer, and American Stock Transfer & Trust Company, LLC, as Warrant Agent, dated as of May 4, 2017 (incorporated by reference to Exhibit 10.4 of Legacy Amplify’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).

10.4#	—	Form of Option Forfeiture Agreement (incorporated by reference to Exhibit 10.7 to Legacy Amplify’s Annual Report on Form 10-K (File No. 001-35364) filed on March 6, 2019).

10.5	—	Form of 2018 RSU Award Agreement (Executives) (incorporated by reference to Exhibit 10.6 to Legacy Amplify’s Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 8, 2018).

10.6	—	Form of 2018 RSU Award Agreement (incorporated by reference to Exhibit 10.20 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

10.7	—	Form of 2019 RSU Award Agreement (Executives) (incorporated by reference to Exhibit 10.21 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

10.8	—	Form of 2019 RSU Award Agreement (incorporated by reference to Exhibit 10.22 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

10.9	—	Form of Stock Option Award Agreement (incorporated by reference to Exhibit 99.2 of Legacy Amplify’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).

Exhibit Number		Description
10.10	—	Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 99.3 of Legacy Amplify’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).

10.11	—	Form of Restricted Stock Unit Award Agreement under the Amplify Energy Corp. 2017 Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.2 of Legacy Amplify’s Registration Statement on Form S-8 (File No. 333-218745) filed on June 14, 2017).

10.12#	—	Amplify Energy Corp. Management Incentive Plan (incorporated by reference to Exhibit 99.1 of Legacy Amplify’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).

10.13	—	Credit Agreement, dated as of November 2, 2018, among Amplify Energy Operating LLC, Amplify Acquisitionco. Inc., as parent , Bank of Montreal, as administrative agent and an L/C issuer, and the other lenders and agents from time to time party thereto (incorporated by reference to Exhibit 10.2 of Quarterly Report on Form 10-Q (File No. 001-35364) filed on November 7, 2018).

10.14	—	First Amendment to Credit Agreement, dated May 5, 2019, by and among Amplify Energy Operating LLC, Amplify Acquisitionco Inc., Legacy Amplify, the guarantors party thereto, lenders party thereto and Bank of Montreal, as administrative agent (incorporated by reference to Exhibit 10.1 of Legacy Amplify’s Current Report on Form 8-K (File No. 001-35364) filed on May 6, 2019).

10.15	—	Second Amendment to Credit Agreement, dated July 16, 2019, by and among Amplify Energy Operating LLC, Amplify Acquisitionco Inc., Legacy Amplify, the guarantors party thereto, lenders party thereto and Bank of Montreal, as administrative agent (incorporated by reference to Exhibit 10.1 of Legacy Amplify’s Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2019).

10.16	—	Borrowing Base Redetermination, Commitment Increase and Joinder Agreement to Credit Agreement, dated August 6, 2019, by and among Amplify Energy Operating LLC, Amplify Acquisitionco LLC, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (incorporated by reference to Exhibit 10.7 of Legacy Amplify’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

10.17	—	Letter Agreement, dated as of December 21, 2018, among Amplify Energy Operating LLC, Amplify Acquisitionco, Inc., as parent, Bank of Montreal, as administrative agent and L/C issuer, and the other lenders and agents from time to time party thereto (incorporated by reference to Exhibit 10.21 to Legacy Amplify’s Annual Report on Form 10-K (File No. 001-35364) filed on March 6, 2019).

10.18#	—	Amplify Energy Corp. 2017 Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.1 of Legacy Amplify’s Registration Statement on Form S-8 (File No. 333-218745) filed on June 14, 2017).

10.19	—	Employment Agreement, dated May 5, 2018, by and between Legacy Amplify and Kenneth Mariani (incorporated by reference to Exhibit 10.2 to Legacy Amplify’s Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 8, 2018).

10.20	—	Employment Agreement, dated May 3, 2019, by and between Legacy Amplify and Martyn Willsher (incorporated by reference to Exhibit 10.1 to Legacy Amplify’s Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 9, 2019).

10.21	—	Employment Agreement, dated May 3, 2019, by and between Legacy Amplify and Richard P. Smiley (incorporated by reference to Exhibit 10.2 to Legacy Amplify’s Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 9, 2019).

10.22	—	Employment Agreement, dated May 3, 2019, by and between Legacy Amplify and Eric M. Willis (incorporated by reference to Exhibit 10.3 to Legacy Amplify’s Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 9, 2019).

10.23	—	Employment Agreement, dated May 1, 2019, by and between Legacy Amplify and Denise DuBard (incorporated by reference to Exhibit 10.15 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

10.24	—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.16 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

21.1*	—	List of Subsidiaries of Amplify Energy Corp.

23.1*	—	Consent of Cawley, Gillespie and Associates, Inc.

Exhibit Number				Description
23.2*		—	Consent of KPMG LLP

31.1*	—			Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

31.2*	—			Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

32.1*	—			Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1*	—			Report of Cawley, Gillespie and Associates, Inc.

101.CAL*	—			XBRL Calculation Linkbase Document

101.DEF*	—			XBRL Definition Linkbase Document

101.INS*	—			XBRL Instance Document

101.LAB*	—			XBRL Labels Linkbase Document

101.PRE*	—			XBRL Presentation Linkbase Document

101.SCH*	—			XBRL Schema Document

*	Filed or furnished as an exhibit to this annual report on Form 10-K.

#	Management contract or compensatory plan or arrangement.

##	Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

ITEM 16.

Form 10-K Summary

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Amplify Energy Corp.
	(Registrant)

Date: March 5, 2020	By:	/s/ *Martyn Willsher*
	Name:	Martyn Willsher
	Title:	Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.

Name	Title (Position with Amplify Energy Corp.)	Date

/s/ *Kenneth Mariani*	President, Chief Executive Officer and Director	March 5, 2020
Kenneth Mariani	(Principal Executive Officer)

/s/ *Martyn Willsher*	Senior Vice President and Chief Financial Officer	March 5, 2020
Martyn Willsher	(Principal Financial Officer)

/s/ *Denise DuBard*	Vice President and Chief Accounting Officer	March 5, 2020
Denise DuBard	(Principal Accounting Officer)

/s/ *David H. Proman*	Director and Chairman	March 5, 2020
David H. Proman

/s/ *Christopher W. Hamm*	Director	March 5, 2020
Christopher W. Hamm

/s/ *Scott L. Hoffman*	Director	March 5, 2020
Scott L. Hoffman

/s/ *Randal T. Klein*	Director	March 5, 2020
Randal T. Klein

/s/ *Evan S. Lederman*	Director	March 5, 2020
Evan S. Lederman

/s/ *Todd R. Snyder*	Director	March 5, 2020
Todd R. Snyder

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

AMPLIFY ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

		Page No.
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018		F-3
Statements of Consolidated Operations for the year ended December 31, 2019, the year ended December 31, 2018 (Successor Period), the period from May 5, 2017 through December 31, 2017 (Successor Period) and the period from January 1, 2017 through May 4, 2017 (Predecessor Period)		F-4
Statements of Consolidated Cash Flows for the year ended December 31, 2019, the year ended December 31, 2018 (Successor Period), the period from May 5, 2017 through December 31, 2017 (Successor Period) and the period from January 1, 2017 through May 4, 2017 (Predecessor Period)		F-5
Statements of Consolidated Equity for the year ended December 31, 2019, for the year ended December 31, 2018 (Successor Period), the period from May 5, 2017 through December 31, 2017 (Successor Period), and the period from January 1, 2017 through May 4, 2017 (Predecessor Period)		F-7
Notes to Consolidated Financial Statements
Note 1 – Organization and Basis of Presentation		F-9
Note 2 – Emergence from Voluntary Reorganization under Chapter 11		F-11
Note 3 – Fresh Start Accounting		F-11
Note 4 – Summary of Significant Accounting Policies		F-15
Note 5 – Revenues		F-21
Note 6 – Acquisitions and Divestitures		F-22
Note 7 – Fair Value Measurements of Financial Instruments		F-24
Note 8 – Risk Management and Derivative Instruments		F-26
Note 9 – Asset Retirement Obligations		F-29
Note 10 – Restricted Investments		F-29
Note 11 – Debt		F-29
Note 12 – Equity (Deficit)		F-33
Note 13 – Earnings per Share/Unit		F-35
Note 14 – Equity-based Awards		F-35
Note 15 – Leases		F-43
Note 16 – Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows		F-45
Note 17 – Related Party Transactions		F-46
Note 18 – Commitments and Contingencies		F-46
Note 19 – Income Tax		F-47
Note 20 – Quarterly Financial Information (Unaudited)		F-50
Note 21 – Supplemental Oil and Gas Information (Unaudited)		F-50
Note 22 – Subsequent Events		F-55

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Amplify Energy Corp.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Amplify Energy Corp. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related statements of consolidated operations, equity and cash flows for the year ended December 31, 2019, the year ended December 31, 2018, the period May 5, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through May 4, 2017 (Predecessor) and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the year ended December 31, 2019, the year ended December 31, 2018, the period May 5, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through May 4, 2017 (Predecessor), in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 5, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, on April 14, 2017, the United States Bankruptcy Court for the Southern District of Texas entered an order confirming the plan for reorganization, which became effective on May 4, 2017. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification Topic 852, Reorganizations, for the comparable with prior periods (Predecessor) as described in Note 1.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2011.

Houston, Texas

March 5, 2020

F-2

AMPLIFY ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	December 31,			December 31,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	49,704
Restricted cash		325			325
Accounts receivable		33,145			29,514
Short-term derivative instruments		5,879			18,813
Prepaid expenses and other current assets		13,238			7,241
Total current assets		52,587			105,597
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		797,005			598,331
Support equipment and facilities		140,023			108,760
Other		8,045			6,625
Accumulated depreciation, depletion and impairment		(141,350	)		(85,535	)
Property and equipment, net		803,723			628,181
Long-term derivative instruments		6,364			2,469
Restricted investments		4,622			94,467
Operating lease - long term right-of-use asset		4,406			—
Other long-term assets		5,837			6,129
Total assets	$	877,539		$	836,843

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,310		$	2,345
Revenues payable		29,167			24,779
Accrued liabilities (see Note 16)		23,358			23,155
Short-term derivative instruments		253			139
Total current liabilities		61,088			50,418
Long-term debt (see Note 11)		285,000			294,000
Asset retirement obligations		90,466			75,867
Long-term derivative instruments		305			—
Operating lease liability		2,720			—
Other long-term liabilities		3,753			—
Total liabilities		443,332			420,285
Commitments and contingencies (see Note 18)
Stockholders' equity:
Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding at December 31, 2019 and preferred stock, $0.0001 par value 45,000,000 shares authorized; no shares issued and outstanding at December 31, 2018		—			—
Warrants, 9,153,522 warrants issued and outstanding at December 31, 2019 and 2,173,913 warrants issued and outstanding at December 31, 2018, respectively		4,790			4,788
Common stock, $0.01 par value: 250,000,000 shares authorized; 37,566,540 shares issued and outstanding at December 31, 2019 and common stock, $0.0001 par value 300,000,000 shares authorized; 22,181,881 shares issued and outstanding at December 31, 2018		209			3
Additional paid-in capital		424,399			355,872
Accumulated earnings		4,809			55,895
Total stockholders' equity		434,207			416,558
Total liabilities and equity	$	877,539		$	836,843

See Accompanying Notes to Consolidated Financial Statements.

F-3

AMPLIFY ENERGY CORP.

STATEMENTS OF CONSOLIDATED OPERATIONS

(In thousands, except per share/unit amounts)

				Successor						Predecessor
	For the			For the			Period from			Period from
	Year Ended			Year Ended			May 5, 2017			January 1,
	December 31,			December 31,			through			2017 through
	2019			2018			December 31, 2017			May 4, 2017
Revenues:
Oil and natural gas sales	$	274,607		$	339,840		$	205,176		$	108,970
Other revenues		968			304			303			231
Total revenues		275,575			340,144			205,479			109,201

Costs and expenses:
Lease operating expense		123,918			114,405			74,547			35,568
Gathering, processing, and transportation		18,475			23,231			18,652			10,772
Exploration		51			3,045			32			21
Taxes other than income		18,668			20,364			11,101			5,187
Depreciation, depletion, and amortization		55,843			52,334			35,979			37,717
Impairment expense		2,246			—			—			—
General and administrative expense		55,288			43,129			29,506			31,606
Accretion of asset retirement obligations		5,559			5,711			4,384			3,407
(Gain) loss on commodity derivative instruments		6,700			(8,155	)		31,609			(23,076	)
(Gain) loss on sale of properties		—			3,614			—			—
Other, net		798			943			485			36
Total costs and expenses		287,546			258,621			206,295			101,238
Operating income (loss)		(11,971	)		81,523			(816	)		7,963
Other income (expense):
Interest expense, net		(16,855	)		(21,923	)		(15,936	)		(10,243	)
Other income (expense)		(1,117	)		190			16,981			8
Loss on lease		(4,247	)		—			—			—
Gain (loss) on extinguishment on debt		—			(3,034	)		—			—
Total other income (expense)		(22,219	)		(24,767	)		1,045			(10,235	)
Income (loss) before reorganization items, net and income taxes		(34,190	)		56,756			229			(2,272	)
Reorganization items, net		(1,057	)		(2,147	)		(1,119	)		(88,774	)
Income tax benefit (expense)		50			—			2,176			91
Net income (loss)		(35,197	)		54,609			1,286			(90,955	)
Net income (loss) attributable to Successor/Predecessor	$	(35,197	)	$	54,609		$	1,286		$	(90,955	)

Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor	$	(35,197	)	$	54,609		$	1,286		$	(90,955	)
Net (income) loss allocated to participating restricted stockholders		—			(2,426	)		(35	)		—
Net income (loss) available to common stockholders/limited partners	$	(35,197	)	$	52,183		$	1,251		$	(90,955	)

Earnings per share/unit: (See Note 13)
Basic and diluted earnings per share/unit	$	(1.20	)	$	2.09		$	0.05		$	(1.09	)
Weighted average common shares/units outstanding:
Basic and diluted		29,301			24,959			25,000			83,807

See Accompanying Notes to Consolidated Financial Statements.

F-4

AMPLIFY ENERGY CORP.

STATEMENTS OF CONSOLIDATED CASH FLOWS

(In thousands)

				Successor						Predecessor
	For the			For the			Period from			Period from
	Year Ended			Year Ended			May 5, 2017			January 1, 2017
	December 31,			December 31,			through			through
	2019			2018			December 31, 2017*			May 4, 2017*
Cash flows from operating activities:
Net income (loss)	$	(35,197	)	$	54,609		$	1,286		$	(90,955	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		55,843			52,334			35,979			37,717
Impairment expense		2,246			—			—			—
(Gain) loss on derivative instruments		6,476			(8,155	)		31,609			(23,076	)
Cash settlements (paid) received on expired derivative instruments		4,344			10,087			30,446			15,895
Cash settlements (paid) on terminated derivatives		—			—			—			94,146
Bad debt expense		301			106			—			—
Deferred income tax expense (benefit)		—			—			(2,206	)		(74	)
Amortization and write-off of deferred financing costs		1,174			2,518			2,093			—
(Gain) loss on extinguishment of debt		—			3,034			—			—
Accretion of asset retirement obligations		5,559			5,711			4,384			3,407
(Gain) loss on sale of properties		—			3,614			—			—
Share-based compensation (see Note 14)		4,530			4,374			2,516			3,667
Settlement of asset retirement obligations		(259	)		(767	)		(633	)		(164	)
Write-off of other property, plant & equipment		1,325			—			—			—
Reorganization items, net		—			—			—			68,356
Other		(8	)		—			—			56
Changes in operating assets and liabilities:
Accounts receivable		10,701			5,783			(2,830	)		1,024
Prepaid expenses and other assets		713			623			5,578			735
Payables and accrued liabilities		(13,592	)		7,925			(13,590	)		15,030
Other		3,127			(15	)		10			(266	)
Net cash provided by operating activities		47,283			141,781			94,642			125,498
Cash flows from investing activities:
Cash acquired from the Merger		19,250			—			—			—
Additions to oil and gas properties		(72,709	)		(55,425	)		(52,735	)		(6,211	)
Additions to other property and equipment		(1,081	)		(492	)		(127	)		(76	)
Additions to restricted investments		(155	)		(500	)		(495	)		(209	)
Withdrawals of restricted investments		90,000			62,467			—			—
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold		—			17,113			—			—
Other		10			503			—			—
Net cash provided by (used in) investing activities		35,315			23,666			(53,357	)		(6,496	)
Cash flows from financing activities:
Advances on revolving credit facilities		125,000			315,000			9,000			16,600
Payments on revolving credit facilities		(134,000	)		(397,000	)		(63,000	)		(98,252	)
Repayment of Midstates revolving credit facility		(76,559	)		—			—			—
Deferred financing costs		(882	)		(3,451	)		(642	)		(8,575	)
Dividends to stockholders		(15,889	)		—			—			—
Common stock repurchased and retired under the share repurchase program		(26,203	)		—			—			—
Treasury stock acquired and retired		(3,340	)		—			—			—
Retirement of common stock under tender offer		—			(35,000	)		—			—
Costs incurred in conjunction with tender offer		(107	)		(521	)		—			—
Payment to holders of the Notes		—			—			(8,193	)		(16,446	)
Payment to Predecessor common unitholders		—			—			(1,250	)		—
Contribution from management		—			—			1,500			—
Restricted units returned to plan		(406	)		(847	)		—			(10	)
Other		84			9			(9	)		9
Net cash provided by (used in) financing activities		(132,302	)		(121,810	)		(62,594	)		(106,674	)
Net change in cash, cash equivalents and restricted cash		(49,704	)		43,637			(21,309	)		12,328
Cash, cash equivalents and restricted cash, beginning of period		50,029			6,392			27,701			15,373
Cash, cash equivalents and restricted cash, end of period	$	325		$	50,029		$	6,392		$	27,701

See Accompanying Notes to Consolidated Financial Statements.

F-5

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

F-6

AMPLIFY ENERGY CORP.

STATEMENTS OF CONSOLIDATED EQUITY (PREDECESSOR)

(In thousands)

	Partner's Equity
	Limited Partners
	Common
	Units
Balance at December 31, 2016 (Predecessor)	$	99,489
Net income (loss)		(90,955	)
Cancellation and amortization of equity/unit-based awards		3,713
Restricted units repurchased and other		(2	)
Issuance of common stock to Predecessor common unitholders		(7,707	)
Issuance of warrants to Predecessor common unitholders		(4,788	)
Contribution from management		1,500
Settlement with Predecessor common unitholders		(1,250	)
Balance at May 4, 2017 (Predecessor)	$	—

F-7

AMPLIFY ENERGY CORP.

STATEMENTS OF CONSOLIDATED EQUITY (SUCCESSOR)

(In thousands)

	Stockholders' Equity
	Common Stock		Warrants		Additional Paid-in Capital			Treasury Stock			Accumulated Earnings (Deficit)			Total
Issuance of Successor common stock to holders of the Notes	$	3	$	—	$	377,642		$	—		$	—		$	377,645
Issuance of Successor warrants to Predecessor common unitholders		—		4,788		—			—			—			4,788
Issuance of Successor common stock to Predecessor common unitholders		—		—		7,707			—			—			7,707
Balance at May 5, 2017 (Successor)		3		4,788		385,349			—			—			390,140
Net income (loss)		—		—		—			—			1,286			1,286
Share-based compensation expense		—		—		2,516			—			—			2,516
Other		—		—		(9	)		—			—			(9	)
Balance at December 31, 2017 (Successor)		3		4,788		387,856			—			1,286			393,933
Net income (loss)		—		—		—			—			54,609			54,609
Tender offer distribution		—		—		(35,520	)		—			—			(35,520	)
Share-based compensation expense		—		—		4,374			—			—			4,374
Restricted shares repurchased		—		—		(847	)		—			—			(847	)
Other		—		—		9			—			—			9
Balance at December 31, 2018 (Successor)		3		4,788		355,872			—			55,895			416,558
Net income (loss)		—		—		—			—			(35,197	)		(35,197	)
Equity transactions related to the Merger		206		2		94,059			(2,723	)		—			91,544
Acquisition of treasury stock		—		—		—			(618	)		—			(618	)
Retirement of treasury shares		—		—		(3,341	)		3,341			—			—
Share-based compensation expense		—		—		4,530			—			—			4,530
Cost incurred in conjunction with tender offer		—		—		(107	)		—			—			(107	)
Common stock repurchased and retired under the share repurchase program		—		—		(26,203	)		—			—			(26,203	)
Dividends		—		—		—			—			(15,889	)		(15,889	)
Restricted shares repurchased		—		—		(406	)		—			—			(406	)
Other		—		—		(5	)		—						(5	)
Balance at December 31, 2019	$	209	$	4,790	$	424,399		$	—		$	4,809		$	434,207

See Accompanying Notes to Consolidated Financial Statements.

F-8

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

General

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

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

When referring to Legacy Amplify, the intent is to refer to Amplify Energy Corp. prior to the Merger, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Legacy Amplify is the successor reporting company (the “Successor”) of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended. When referring to the “Predecessor” or the “Company” in reference to the period prior to Legacy Amplify emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

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 one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas/North Louisiana and South Texas. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.

Definitive Merger Agreement

On May 5, 2019, as discussed above, the Company entered into the Merger Agreement pursuant to which Legacy Amplify merged with a subsidiary of Midstates in an all-stock merger-of-equals. Under the terms of the Merger Agreement, Legacy Amplify stockholders received 0.933 shares of newly issued Company common stock for each share of Legacy Amplify common stock that they owned. The Merger closed on August 6, 2019. See Note 6 for additional information.

Emergence from Voluntary Reorganization under Chapter 11

On January 16, 2017 (the “Petition Date”), MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re: Memorial Production Partners LP, et al. (Case No. 17-30262). On April 14, 2017, the Bankruptcy Court entered an order approving the Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (as amended and supplemented, the “Plan”). On May 4, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and Legacy Amplify emerged from bankruptcy.

Basis of Presentation

Our Consolidated Financial Statements included herein have been prepared pursuant to the rule and guidelines of the Securities and Exchange Commission (the “SEC”).

F-9

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All material intercompany transactions and balances have been eliminated in preparation of our Consolidated Financial Statements. The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gain (loss) on extinguishment of deferred finance cost were previously accounted for as interest expense, net and are now being presented as gain (loss) on extinguishment of debt on our Statement of Consolidated Operations.

The Consolidated Financial Statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s Statement of Consolidated Operations.

The Company adopted the new accounting pronouncement related to the presentation of statement of cash flows — restricted cash in the first quarter of 2018. A retrospective change for the period from January 1, 2017 through May 4, 2017 and May 5, 2017 through December 31, 2017 on the Statement of Consolidated Cash Flows as previously presented was required due to adoption. The table below sets forth the retrospective adjustments for the periods presented:

	Predecessor
	Previously Reported Period from January 1, 2017 through May 4, 2017			Adjustment Effect		As Adjusted Period from January 1, 2017 through May 4, 2017
	(In thousands)
Changes in operating assets and liabilities:
Restricted cash	$	(7,561	)	$	7,561	$	—
Net cash provided by operating activities		117,937			7,561		125,498
Net change in cash and cash equivalents		4,767			7,561		12,328
Cash and cash equivalents, end of period		20,140			7,561		27,701

	Successor
	Previously Reported Period from May 5, 2017 through December 31, 2017			Adjustment Effect			As Adjusted Period from May 5, 2017 through December 30, 2017
	(In thousands)
Changes in operating assets and liabilities:
Restricted cash	$	7,561		$	(7,561	)	$	—
Net cash provided by operating activities		102,203			(7,561	)		94,642
Net change in cash and cash equivalents		(13,748	)		(7,561	)		(21,309	)
Cash and cash equivalents, end of period		6,392			—			6,392

Comparability of Financial Statements to Prior Periods

As discussed in further detail in Note 3 below, Legacy Amplify adopted and applied the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Consolidated Financial Statements and Notes after May 4, 2017, are not comparable to the Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Consolidated Financial Statements and Notes as the “Successor” for periods subsequent to May 4, 2017 and “Predecessor” for periods prior to May 5, 2017. Furthermore, our Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor.

F-10

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Emergence from Voluntary Reorganization under Chapter 11

On the Petition Date, the Debtors filed voluntary petitions under the Bankruptcy Code in the Bankruptcy Court to pursue a Joint Chapter 11 Plan of Reorganization for the Debtors. The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262).

On April 14, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) approving the Plan.

On the Effective Date, the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and Legacy Amplify emerged from bankruptcy. Although Legacy Amplify is no longer a debtor-in-possession, the Company was a debtor-in-possession from January 16, 2017 through May 4, 2017. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to Legacy Amplify’s financial condition and results of operations for the period presented.

Plan of Reorganization

In accordance with the Plan, on the Effective Date:

•

The Successor issued (i) 25,000,000 new shares (the “New Common Shares”) of its common stock, par value $0.0001 per share (“common stock”); and (ii) warrants (the “Warrants”) to purchase up to 2,173,913 shares of Legacy Amplify’s common stock exercisable for a five-year period commencing on the Effective Date entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common shares (including common shares as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common shares issuable under the Management Incentive Plan (the “MIP”)), at a per share exercise price of $42.60.

•

The holders of claims under the Predecessor’s revolving credit facility received a full recovery, consisting of a cash pay down and their pro rata share of the $1 billion exit senior secured reserve-based revolving credit facility (the “Emergence Credit Facility”), as further discussed in Note 11.

•

The 7.625% senior notes due May 2021 (“2021 Senior Notes”) and 6.875% senior notes due August 2022 (“2022 Senior Notes” and collectively, the “Notes”) were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Shares representing, in the aggregate, 98% of the New Common Shares on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants). Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.

•

The Predecessor’s common units were cancelled, and each common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million.

•

The holders of administrative expense claims, priority tax claims, other priority claims and general unsecured creditors of the Predecessor received in exchange for their claims payment in full in cash or otherwise had their rights unimpaired under Title 11 of the United States Code.

•

The Successor entered into a stockholders agreement with certain parties pursuant to which the Successor agreed to, at the direction of such stockholders, use commercially reasonable efforts to effect the sale of their common stock.

•

The Successor entered into a registration rights agreement with certain parties pursuant to which the Successor agreed to, among other things, file a registration statement with the SEC within 90 days of the receipt of a request from the stockholders party thereto covering the offer and resale of the common stock held by such stockholders.

•

The Company’s MIP became effective, such that an aggregate of 2,322,404 shares of Legacy Amplify’s common stock became available for grant pursuant to awards under the MIP.

•

The terms of the Predecessor’s general partner’s board of directors automatically expired on the Effective Date. The Successor formed a new seven-member board of directors consisting of the President and Chief Executive Officer, one director of the Predecessor, and five new members designated by certain parties to the plan support agreement.

Note 3. Fresh Start Accounting

Upon emergence from the Chapter 11 proceedings on May 4, 2017, Legacy Amplify adopted fresh start accounting as required by GAAP. Legacy Amplify met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of Legacy Amplify and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims.

F-11

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Reorganization Value

The Successor’s enterprise value, as approved by the Bankruptcy Court, was estimated to be within a range of $700 million to $900 million, with a midpoint estimate of approximately $800 million. Enterprise value represents the estimated fair value of a company’s interest-bearing debt and its shareholders’ equity. Based on the estimates and assumptions utilized in our fresh start accounting process, Legacy Amplify estimated the Successor’s enterprise value to be approximately $800 million before the consideration of cash and cash equivalents on hand at the Effective Date. Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived from the Successor’s enterprise value, was allocated to our individual assets based on their estimated fair values.

The following table is a reconciliation of the enterprise value to the reorganization value of the Successor assets at the Effective Date (in thousands):

Enterprise value	$	800,000
Plus: Cash and cash equivalents		20,140
Plus: Other working capital liabilities		63,817
Plus: Other long-term liabilities		97,470
Reorganization value of Successor assets	$	981,427

Legacy Amplify’s assets consist primarily of producing oil and natural gas properties. The fair values of proved and unproved oil and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. These inputs require significant judgments and estimates by Legacy Amplify’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in Legacy Amplify’s estimated cash flows are the product of a process that begins with NYMEX forward curve pricing and is adjusted for estimated location and quality differentials, as well as other factors as necessary that Legacy Amplify’s management believed would impact realizable prices. The fair value of support equipment and facilities were estimated using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets.

See below under the caption “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of Legacy Amplify’s various other significant assets and liabilities.

F-12

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidated Balance Sheet

The adjustments included in the following condensed consolidated balance sheet reflected the effect of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.

	As of May 4, 2017
			Reorganization				Fresh Start
	Predecessor		Adjustments (1)				Adjustments				Successor
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	83,050	$	(62,910	)	(2)	$	—			$	20,140
Restricted cash		—		7,411		(3)		—				7,411
Accounts receivable		33,560		—				—				33,560
Short-term derivative instruments		51,329		—				—				51,329
Prepaid expenses and other current assets		10,229		675		(4)		—				10,904
Total current assets		178,168		(54,824	)			—				123,344
Property and equipment, net		1,551,500		—				(894,164	)	(11)		657,336
Long-term derivative instruments		33,800		—				—				33,800
Restricted investments		156,443		—				—				156,443
Other long-term assets		1,929		8,575		(5)		—				10,504
Total assets	$	1,921,840	$	(46,249	)		$	(894,164	)		$	981,427

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,501	$	1,389		(6)	$	—			$	2,890
Revenues payable		22,747		—				—				22,747
Accrued liabilities		36,954		2,939		(7)		(1,713	)	(12)		38,180
Current portion of long-term debt		454,799		(454,799	)	(8)		—				—
Total current liabilities		516,001		(450,471	)			(1,713	)			63,817
Liabilities subject to compromise		1,162,437		(1,162,437	)	(9)		—				—
Long-term debt		—		430,000		(8)		—				430,000
Asset retirement obligations		158,114		—				(62,928	)	(13)		95,186
Deferred tax liabilities		2,206		—				—				2,206
Other long-term liabilities		2,481		—				(2,403	)	(12)		78
Total liabilities		1,841,239		(1,182,908	)			(67,044	)			591,287
Commitments and contingencies (see Note 18)
Stockholders'/partners' equity:
Predecessor common units		80,601		(80,601	)	(10)		—				—
Successor warrants		—		4,788		(10)		—				4,788
Successor common stock		—		3		(10)		—				3
Successor additional paid-in capital		—		1,212,469		(10)		(827,120	)	(14)		385,349
Total stockholders'/ partners' equity		80,601		1,136,659				(827,120	)			390,140
Total liabilities and equity	$	1,921,840	$	(46,249	)		$	(894,164	)		$	981,427

Reorganization Adjustments

(1)

Reflected amounts recorded as of the Effective Date for the implementation of the Plan, including among other items, settlement of the Predecessor’s liabilities subject to compromise, cancellation of the Predecessor’s equity, issuance of the Successor New Common Shares and the Warrants, repayment of certain of Predecessor’s debt and settlement with holders of the Notes.

F-13

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(2)	Reflected the changes in cash and cash equivalents, including the following (in thousands):

Payment on the Predecessor's revolving credit facility	$	(24,799	)
Payment to holders of the Notes (1)		(16,446	)
Payment of fees related to Emergence Credit Facility		(8,575	)
Funding of the professional fees escrow account		(7,411	)
Payment of professional fees		(4,295	)
Other		(1,384	)
Changes in cash and cash equivalents	$	(62,910	)

(1)

The total cash settlement to the holders of the Notes was approximately $24.6 million, of which $16.4 million was paid upon emergence and $8.2 million was paid post-emergence and is reflected in accrued liabilities in the above condensed consolidated balance sheet.

(3)	Reflected the transfer to restricted cash to fund the professional fees escrow account.

(4)	Reflected the pre-payment of certain professional fees.

(5)	Reflected the deferred financing costs related to the Emergence Credit Facility.

(6)	Reflected the recognition of payables for general unsecured claims.

(7)	Net increase in accrued liabilities reflected the following (in thousands):

Recognition of liability for settlement with holders of the Notes	$	8,193
Payment of professional fees		(4,295	)
Recognition of contribution from management		(1,500	)
Recognition of settlement with Predecessor common unitholders		1,250
Other		(709	)
Net increase in accrued liabilities due to reorganization items	$	2,939

(8)	Reflected a repayment of $24.8 million on the Predecessor’s revolving credit facility and the reclassification of $430.0 million in borrowings under the Emergence Credit Facility to long-term debt.

(9)	Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands):

Accounts payable	$	1,389
Accrued interest payable		49,796
Debt		1,111,252
Total liabilities subject to compromise of Predecessor		1,162,437
Recognition of payables for general unsecured claims		(1,389	)
Recognition of settlement with holders of the Notes		(24,639	)
Issuance of common stock to holders of the Notes		(377,645	)
Gain on settlement of liabilities subject to compromise	$	758,764

(10)	Net increase in our stockholders’/partners’ equity reflects the following (in thousands):

Issuance of common stock to holders of the Notes	$	377,645
Issuance of common stock to Predecessor common unitholders		7,707
Cancellation of the Predecessor's units issued and outstanding		80,601
Recognition on gain on settlement of liabilities subject to compromise		758,764
Recognition of issuance of common stock to Predecessor common unitholders		(7,707	)
Recognition of issuance of warrants to Predecessor common unitholders		(4,788	)
Recognition of contribution from management		1,500
Recognition of settlement with Predecessor common unitholders		(1,250	)
Par value of common stock		(3	)
Change in Successor additional paid-in capital		1,212,469
Issuance of warrants to Predecessor common unitholders		4,788
Par value of common stock		3
Predecessor units issued and outstanding		(80,601	)
Net increase in capital accounts	$	1,136,659

F-14

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fresh Start Adjustments

(11)	Reflected a decrease of property and equipment, net based on the methodology discussed above and the elimination of accumulated depreciation, depletion and impairment. The fresh start adjustments to property and equipment, net are as follow:

	Predecessor			Fresh Start Adjustments			Successor
	(In thousands)
Property and equipment at cost:
Proved oil and natural gas properties	$	3,124,137		$	(2,615,076	)	$	509,061
Support equipment and facilities		199,463			(101,883	)		97,580
Unproved oil and natural gas properties		—			44,688			44,688
Other		15,420			(9,413	)		6,007
Property and equipment		3,339,020			(2,681,684	)		657,336
Accumulated depreciation, depletion and impairment		(1,787,520	)		1,787,520			—
Property and equipment, net	$	1,551,500		$	(894,164	)	$	657,336

(12)	Reflected the write-off of the deferred rent and loss on sublease liabilities.

(13)

Reflected a decrease of $62.9 million for asset retirement obligations. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk free rate.

(14)	Reflected the cumulative impact of our fresh start accounting adjustments discussed above.

Reorganization Items, Net

The Company has incurred significant costs associated with the reorganization. These costs, which are expensed as incurred, were expected to significantly affect the Company’s results of operations. Reorganization items, net represent costs and income directly associated with Legacy Amplify’s Chapter 11 proceedings since the Petition Date.

The following table summarizes the components of reorganization items, net included in the accompanying Statements of Consolidated Operations (in thousands):

				Successor						Predecessor
	For the			For the			Period from			Period from
	Year Ended			Year Ended			May 5, 2017			January 1, 2017
	December 31,			December 31,			through			through
	2019			2018			December 31, 2017			May 4, 2017
Gain on settlement of liabilities subject to compromise	$	—		$	—		$	—		$	758,764
Fresh start valuation adjustments		—			—			—			(827,120	)
Professional fees		(430	)		(864	)		(724	)		(19,824	)
Other		(627	)		(1,283	)		(395	)		(594	)
Reorganization items, net	$	(1,057	)	$	(2,147	)	$	(1,119	)	$	(88,774	)

Note 4. Summary of Significant Accounting Policies

Fresh Start Accounting

Upon the Effective Date, Legacy Amplify adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of Legacy Amplify and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims. Fresh start accounting involved a comprehensive valuation process in which we determined the fair value of all of Legacy Amplify’s assets and liabilities on the Effective Date. See Note 3 for additional information.

F-15

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Use of Estimates

Business Combinations

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts which are held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, individuals and others who own interests in the properties operated by us. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. We recorded $1.5 million and $1.2 million as an allowance for doubtful accounts at December 31, 2019 and 2018, respectively.

If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.

F-16

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, seismic costs and delay rental payments attributable to unproved locations are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Wyoming and California assets, are depreciated using the straight-line method generally based on estimated useful lives of twelve to twenty-four years.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2019 and 2018.

Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the Consolidated Financial Statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged Cawley, Gillespie and Associates, Inc. (“CG&A”), our independent reserve engineers, to prepare our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2019.

Other Property & Equipment

Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years.

Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense, net in the statement of operations. These restricted investments may consist of money market deposit accounts and U.S. Government securities. See Note 10 and Note 18 for additional information.

F-17

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Debt Issuance Costs

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2019 and 2018 and the period from May 5, 2017 through December 31, 2017 was approximately $1.2 million, $2.5 million and $2.1 million, respectively. No amortization of deferred financing cost was recorded for the period from January 1, 2017 through May 4, 2017 as the unamortized amount of deferred financing cost at December 31, 2016 was written off due to (i) the uncertainty regarding the Predecessor’s ability to cure the default that existed at December 31, 2016, (ii) the Predecessor’s inability to comply with certain financial covenants contained in our Predecessor’s revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. No impairment expense related to our proved properties was recorded for the years ended December 31, 2019 and 2018, the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017.

Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in impairment expense. We recognized $2.2 million in impairment expense for certain unproved leasehold costs for the year ended December 31, 2019. We did not record any impairments related to unproved properties for the year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017.

Significant declines in commodity prices, further changes to the Company’s drilling or development plans, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional future impairments to proved and unproved oil and gas properties.

Asset Retirement Obligations

Book Overdrafts

Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.

Revenue Recognition

F-18

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance and requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The standard was effective for the Company starting January 1, 2018, and the Company adopted the standard using a modified retrospective approach. See Note 5 for additional information.

The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:

Successor

Predecessor

For the

Period from

Year Ended

December 31,

through

2019

2018

Major customers:

Phillips 66

27%

23%

19%

Sinclair Oil & Gas Company

21%

19%

20%

CIMA Energy

n/a

10%

11%

n/a

BP America Production Company

13%

n/a

10%

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, collars and puts) are used to reduce the impact of natural gas and oil price fluctuations. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the years ended December 31, 2019 and 2018 and the period from May 5, 2017 through December 31, 2017 we had $0.2 million, $0.5 million and $0.4 million in capitalized interest, respectively. No capitalized interest recorded for the period from January 1, 2017 through May 4, 2017.

Income Tax

We are a corporation subject to federal and certain state income taxes. Our Predecessor was organized as a pass-through entity for federal and most state income tax purposes. Certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax for activity in the state of Texas.

We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our Statement of Consolidated Operations.

We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination by taxing authorities, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. Although we believe our assumptions, judgements and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.

F-19

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The provisions of the Tax Act that impact us include, but are not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) temporary bonus depreciation that will allow for full expensing of qualified property, and (4) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80 percent of taxable income.

Earnings Per Share/Unit

Basic and diluted earnings per share/unit (“EPS” or “EPU”) is determined by dividing net income or loss available to the common stockholders/limited partners by the weighted average number of outstanding shares/units during the period. Diluted earnings (loss) per common share is calculated under the two-class method and the treasury stock method by dividing net income (loss) available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. Net income or loss available to the Predecessor limited partners was determined by applying the two-class method. The two-class method of computing the Predecessor’s EPU was an earnings allocation formula that determined EPU based on distributions declared. The amount of net income or loss used in the determination of EPU was reduced (or increased) by the amount of available cash that had been distributed to the Predecessor’s limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings were allocated to the Predecessor’s limited partners in accordance with the contractual terms of the Predecessor’s partnership agreement. The total earnings allocated to the Predecessor’s limited partners was determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participated in distributions. See Note 13 for additional information.

Equity Compensation

The fair value of equity-classified awards (e.g., restricted common unit awards, restricted stock units or stock options) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom units awards) are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. We currently have awards subject to performance criteria; such awards would vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 14 for further information.

Recently Adopted Accounting Pronouncements

Lease Recognition

In February 2016, the Financial Accounting Standards Board (“FASB”) issued guidance regarding the accounting for leases. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The Company is the lessee under various agreements for office space, compressors, equipment, vehicles and surface rentals (right of use assets) that are currently accounted for as operating leases.

The Company applied the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the modified retrospective approach with a cumulative impact to retained earnings in that period, and including several optional practical expedients relating to leases commenced before the effective date. The practical expedients the Company adopted are: (1) the original correct assessment of a contract containing a lease will be accepted without further review on all existing or expired contracts; (2) the original lease classification as an operating lease will convert as an operating lease under the new guidance; (3) initial direct costs for any existing leases will not be reassessed; (4) existing land easements or right of use agreements will continue under current accounting policy and only new agreements will be evaluated in the future; and (5) short-term leases for twelve months or less will not be evaluated under the guidance.

See Note 15 for additional information regarding the adoption of the leases standard.

New Accounting Pronouncements

Fair Value Measurement. In August 2018, the FASB issued an amendment to modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement. Certain disclosure requirements were removed, modified and added and primarily relate to Level 3 hierarchy measurements and changes to non-public entities disclosures. The guidance is effective for all entities for fiscal years and interim periods within those fiscal years, beginning after December 15, 2019. The impact of this guidance is not expected to have a material impact on the Company.

F-20

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Instruments — Credit Losses. In May 2019 the FASB issued an accounting standards update to provide entities with an option to irrevocably elect the fair value option applied on an instrument-by-instrument basis for certain financial assets upon the adoption. The fair value option election does not apply to held-to-maturity debt securities. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The Company is currently evaluating the impact of this guidance and does not expect the guidance to have a material impact on the Company’s financial statements.

Income Taxes – Simplifying the Accounting for Income Taxes. In December 2019, the FASB issued an accounting standards update which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. This accounting standards update removes the following exceptions: (i) exception to the incremental approach for intraperiod tax allocation when there is a loss continuing operations and income or a gain from other items; (ii) exception to the requirements to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment; (iii) exception to the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary; and (iv) exception to the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. The amendments in the accounting standards update also improve consistency and simplify other areas of Topic 740 by clarifying and amending existing guidance. The new guidance is effective for fiscal years and interim periods within those fiscal years, beginning December 15, 2020. The Company is currently evaluating the impact of this guidance and does not expect the guidance to have a material impact on the Company's financial statements.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Note 5. Revenues

Revenue from contracts with customers

As discussed in Note 4, the Company adopted Accounting Standard Update (ASU) No. 2014-09, revenue from contracts with customers (ASC 606), on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity and did not materially change the Company's amount and timing of revenues. The Company applied the ASU only to contracts that were not completed as of January 1, 2018.

The reclassification of certain fees between oil and natural gas sales and gathering, processing and transportation is the result of the Company’s assessment of the point in time at which its performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. 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.

Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2019.

Disaggregation of Revenue

We have identified three material revenue streams in our business: oil, natural gas and NGLs. The following table present our revenues disaggregated by revenue stream.

	For the Year Ended
	December 31,
	2019		2018
	(in thousands)
Revenues
Oil	$	192,944	$	209,066
NGLs		22,347		42,463
Natural gas		59,316		88,311
Oil and natural gas sales	$	274,607	$	339,840

F-21

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contract Balances

Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $31.9 million at December 31, 2019 and $25.0 million at December 31, 2018.

Transaction Price Allocated to Remaining Performance Obligations

For our contracts that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our contracts that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Note 6. Acquisitions and Divestitures

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under our revolving credit facility and our Predecessor revolving credit facility.

The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

Acquisition and Divestiture related expenses

Acquisition and divestiture related expenses for third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

Successor

Predecessor

For the

Period from

Year Ended

December 31,

through

2019

2018

17,305

205

609

—

Business Combination

Acquisitions qualifying as a business combination are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired, and liabilities assumed be recognized on the condensed consolidated balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired, and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.

Merger

On May 5, 2019, Midstates, Legacy Amplify and Merger Sub entered into the Merger Agreement pursuant to which, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates. At the effective time of the Merger, each share of Legacy Amplify common stock issued and outstanding immediately prior to the effective time (other than excluded shares) were cancelled and converted into the right to receive 0.933 shares of Midstates common stock, par value $0.01 per share. On August 6, 2019, the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.”

F-22

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Purchase Price Allocation

The Merger has been accounted for using the acquisition method, with Legacy Amplify treated as the acquirer for accounting purposes. The following table represents the allocation of the total purchase price of Midstates to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Consideration:
Fair value of Midstates common stock issued in the Merger (a)	$	90,150
Fair value of Midstates warrants issued in the Merger		2
Value of shares to be issued		90,152
Fair value of Legacy Amplify restricted share consideration		832
Fair value of Legacy Amplify PSU consideration		557
Total consideration	$	91,541

Fair value of liabilities assumed:
Current liabilities	$	24,135
Long-term debt		76,559
Long-term asset retirement obligation		9,440
Other long-term liabilities		5,067
Amounts attributable to liabilities assumed	$	115,201

Fair value of assets acquired:
Cash and cash equivalents	$	19,250
Other current assets		17,862
Oil and natural gas properties		149,421
Other property and equipment		1,694
Long-term asset retirement cost		9,440
Other non-current assets		9,075
Amounts attributable to assets acquired	$	206,742

Total identifiable net assets	$	91,541

(a)

Based on 20,415,005 Midstates common shares issued at closing at $4.12 per share (closing price as of August 6, 2019).

We included in our Condensed Consolidated Statements of Operations revenues of $31.8 million, direct operating expense of $34.0 million and other expenses of $0.4 million for our Oklahoma properties for the period after the Merger closed.

During the three months ended September 30, 2019, the Company completed an analysis of Midstates’ asset retirement obligations as of the acquisition date. Based on this analysis, the Company recorded a measurement period adjustment of $0.9 million to increase the asset retirement obligations liability.

During the quarter ended September 30, 2019, the Company completed an analysis of Midstates’ leases under ASC 842 as of the acquisition date. Based on this analysis, the Company recorded an operating lease right of use asset and liability of approximately $0.3 million.

Unaudited Pro Forma Financials

The following unaudited pro forma financial information for the year ended December 31, 2019 and 2018, respectively, is based on our historical consolidated financial statements adjusted to reflect as if the Merger had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in Midstates statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the periods presented, nor is it necessarily indicative of future results.

F-23

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	For the Year Ended
	December 31,
	2019			2018
(Unaudited)	(In thousands, except per unit amounts)
Revenues	$	336,326		$	545,226
Net income (loss)		(22,926	)		146,845
Earnings per share:
Basic	$	(0.78	)	$	3.18
Diluted	$	(0.78	)	$	3.18

2018 Acquisitions & Divestitures

On May 30, 2018, we closed a transaction to divest certain of our non-core assets located in South Texas (the “South Texas Divestiture”) for total proceeds of approximately $17.1 million, including post-closing adjustments, which includes $18.6 million in cash, $0.5 million in accounts payable and $0.9 million paid in legal and advisor expenses. We recorded a loss on sale of properties of approximately $3.6 million for the year ended December 31, 2018, in “(gain) loss on sale of properties” in the accompanying Statements of Consolidated Operations. The net proceeds from the sale were used to reduce outstanding borrowings under our Emergence Credit Facility (as defined below). This disposition did not qualify as a discontinued operation.

There were no material acquisitions for the year ended December 31, 2018.

2017 Acquisitions & Divestitures

There were no material acquisitions or divestitures the period from January 1, 2017 through May 4, 2017 or for the period from May 5, 2017 through December 31, 2017.

Note 7. 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). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2019 and 2018, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents (Level 1), accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2019 and December 31, 2018. 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. See Note 11 for the estimated fair value of our outstanding fixed-rate debt.

The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2019 and December 31, 2018 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

F-24

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2019 and December 31, 2018 for each of the fair value hierarchy levels:

	Fair Value Measurements at December 31, 2019 Using
	Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	18,509	$	—	$	18,509
Interest rate derivatives		—		595		—		595
Total assets	$	—	$	19,104	$	—	$	19,104

Liabilities:
Commodity derivatives	$	—	$	6,861	$	—	$	6,861
Interest rate derivatives		—		558		—		558
Total liabilities	$	—	$	7,419	$	—	$	7,419

	Fair Value Measurements at December 31, 2018 Using
	Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	25,515	$	—	$	25,515

Liabilities:
Commodity derivatives	$	—	$	4,372	$	—	$	4,372

See Note 8 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the 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 such factors 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 9 for a summary of changes in AROs.

•

If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations is commonly estimated using the depreciated replacement cost approach.

•

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

(i)

We recognized a $2.2 million impairment expense on certain unproved leasehold costs in Oklahoma for the year ended December 31, 2019 due to changes in development plans in the areas of Alfalfa, Major and Woods counties in Oklahoma.

(ii)

No impairment expense was recognized for the year ended December 31, 2018.

F-25

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(iii)

No impairment expense were recognized for the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017.

Note 8. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production. These transactions limit exposure to declines in prices, but also limit the benefits that would be realized if prices increase.

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our previous and current credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2019, after taking into effect netting arrangements, we had no counterparty exposure related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $12.6 million against amounts outstanding under our Revolving Credit Facility at December 31, 2019. See Note 11 for additional information regarding our Revolving Credit Facility.

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, and three-way collars) is used to manage exposure to commodity price volatility.

In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to reduce the amounts outstanding under our Predecessor’s revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes.

We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub. We also enter into oil derivative contracts indexed to either NYMEX WTI or Inter-Continental Exchange (“ICE”) Brent. Our NGL derivative contracts are indexed to Oil Price Information Service Mont Belvieu.

F-26

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2019, the Company had the following open commodity positions:

	2020			2021			2022
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)		600,000			487,500			300,000
Weighted-average fixed price	$	2.53		$	2.48		$	2.46

Collar contracts:
Two-way collars
Average monthly volume (MMBtu)		520,000			162,500			—
Weighted-average floor price	$	2.64		$	2.58		$	—
Weighted-average ceiling price	$	2.96		$	2.84		$	—

Three-way collars
Average monthly volume (MMBtu)		76,000			—			—
Weighted-average ceiling price	$	3.45		$	—		$	—
Weighted-average floor price	$	2.65		$	—		$	—
Weighted-average sub-floor price	$	2.15		$	—		$	—

Natural Gas Basis Swaps:
PEPL basis swaps:
Average monthly volume (MMBtu)		600,000			500,000			—
Weighted-average spread	$	(0.46	)	$	(0.40	)	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		213,050			116,250			30,000
Weighted-average fixed price	$	57.28		$	56.05		$	55.32

Collar contracts:
Two-way collars
Average monthly volume (Bbls)		14,300			—			—
Weighted-average floor price	$	55.00		$	—		$	—
Weighted-average ceiling price	$	62.10		$	—		$	—

Three-way collars
Average monthly volume (Bbls)		30,500			—			—
Weighted-average ceiling price	$	65.75		$	—		$	—
Weighted-average floor price	$	50.00		$	—		$	—
Weighted-average sub-floor price	$	40.00		$	—		$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		65,425			22,800			—
Weighted-average fixed price	$	25.20		$	24.25		$	—

Interest Rate Swaps

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. At December 31, 2019, we had the following interest rate swaps open positions:

	2020			2021			2022
Average Monthly Notional (in thousands)	$	125,000		$	125,000		$	75,000
Weighted-average fixed rate		1.612	%		1.612	%		1.281	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

F-27

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2019 and 2018. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our New Credit Agreement.

		Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
		December 31,			December 31,			December 31,			December 31,
Type	Balance Sheet Location	2019			2019			2018			2018
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	11,518		$	5,887		$	21,217		$	2,543
Interest rate swaps	Short-term derivative instruments		248			253			—			—
Gross fair value			11,766			6,140			21,217			2,543
Netting arrangements			(5,887	)		(5,887	)		(2,404	)		(2,404	)
Net recorded fair value	Short-term derivative instruments	$	5,879		$	253		$	18,813		$	139

Commodity contracts	Long-term derivative instruments	$	6,990		$	973		$	4,298		$	1,829
Interest rate swaps	Long-term derivative instruments		347			305			—			—
Gross fair value			7,337			1,278			4,298			1,829
Netting arrangements			(973	)		(973	)		(1,829	)		(1,829	)
Net recorded fair value	Long-term derivative instruments	$	6,364		$	305		$	2,469		$	—

(Gains) Losses on Derivatives

We do 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 statements of operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

				Successor					Predecessor
	For the			For the			Period from		Period from
	Year Ended			Year Ended			May 5, 2017		January 1, 2017
Statements of	December 31,			December 31,			through		through
Operations Location	2019			2018			December 31, 2017		May 4, 2017
(Gain) loss on commodity derivatives	$	6,700		$	(8,155	)	$	31,609	$	(23,076	)
Interest expense, net		(224	)		—			—		—

F-28

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2019 and 2018, the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017 (in thousands):

				Successor						Predecessor
	For the			For the			Period from			Period from
	Year Ended			Year Ended			May 5, 2017			January 1, 2017
	December 31,			December 31,			through			through
	2019			2018			December 31, 2017			May 4, 2017
Asset retirement obligations at beginning of period	$	76,344		$	100,173		$	96,127		$	155,702
Liabilities added from acquisition or drilling (1)		9,497			89			191			6
Liabilities removed upon sale of wells		—			(15,702	)		—			—
Liabilities settled		(259	)		(767	)		(633	)		(164	)
Accretion expense		5,559			5,711			4,384			3,407
Revision of estimates (2)		(52	)		(13,160	)		104			104
Asset retirement obligation at end of period		91,089			76,344			100,173			159,055
Fresh start adjustment (3)		—			—			—			(62,928	)
Less: Current Portion		623			477			713			941
Asset retirement obligations - long-term portion	$	90,466		$	75,867		$	99,460		$	95,186

(1)	The increase in liabilities added from acquisition or drilling for the year ended December 31, 2019, is primarily due to the Merger with Midstates.

(2)	The decrease in revision of estimates for the year ended December 31, 2018 is primarily due to receiving new cost estimates from third parties regarding the estimated plugging and abandonment costs.

(3)	As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligation at fair value as of the Effective Date.

Note 10. Restricted Investments

	December 31,		December 31,
	2019		2018
	(In thousands)
BOEM platform abandonment (See Note 18)	$	313	$	90,162

SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		4,309		4,305
Restricted investments	$	4,622	$	94,467

On June 24, 2019, the Company received the release of $90.0 million from the Beta Decommissioning Trust Account. See Note 18 for additional information related to the Beta Decommissioning Trust Account.

Note 11. Debt

Our consolidated debt obligations consisted of the following at the dates indicated:

	December 31,		December 31,
	2019		2018
	(In thousands)
Revolving Credit Facility (1)	$	285,000	$	294,000
Long-term debt	$	285,000	$	294,000

(1)

The carrying amount of our Revolving Credit Facility and Emergence Credit Facility approximates fair value because the interest rates are variable and reflective of market rates.

F-29

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revolving Credit Facility

Amplify Energy Operating LLC, our wholly owned subsidiary (“OLLC”), is a party to a reserve-based revolving credit facility (the “Revolving Credit Facility”), subject to a borrowing base of $450.0 million as of December 31, 2019, which is guaranteed by us and all of our current subsidiaries. The Revolving Credit Facility matures on November 2, 2023 and has a semiannual borrowing base redetermination.

The terms and conditions under the Revolving Credit Facility include (but are not limited to) the following:

•

at OLLC’s option, borrowings under the New Credit Agreement will bear interest at the base rate, LIBOR Market Index rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the federal funds effective rate plus 50 basis points, (ii) the rate of interest in effect for each day as publicly announced from time to time by the Agent as its “prime rate”; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points per annum. The applicable margin for base rate loans ranges from 100 to 200 basis points, and the applicable margin for LIBOR loans and LIBOR Market loans ranges from 200 to 300 basis points, in each case depending on the percentage of the borrowing base utilized;

•

the obligations under the Revolving Credit Facility are secured by mortgages on not less than 85% of the PV-9 value of oil and gas properties (and at least 85% of the PV-9 value of the proved, developed and producing oil and gas properties) included in the determination of the borrowing base. OLLC and its other subsidiaries entered into a pledge and security agreement in favor of the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit Agreement are secured by a first priority security interest in substantially all of our assets (subject to permitted liens). Additionally, the Company entered into a non-recourse pledge agreement in favor of the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit Agreement are secured by a pledge and security interest of 100% of the equity interests held by the Company in Amplify Acquisitionco Inc. (“Acquisitionco”);

•

certain financial covenants, including the maintenance of (i) as of the date of determination, a maximum total debt to EBITDAX ratio of 4.00 to 1.00, and (ii) a current ratio of not less than 1.00 to 1.00; and

•

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.

On June 24, 2019, as discussed in Note 18, the Company received the release of $90.0 million from the Beta Decommissioning Trust Account and used the proceeds to reduce amounts outstanding under our Revolving Credit Facility.

Borrowing Base Redetermination

The borrowing base under the Company’s credit agreement is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. On November 8, 2019, as part of the Company’s fall 2019 semiannual borrowing base redetermination, the borrowing base and lender commitments under the Company’s credit agreement among wholly owned subsidiaries of the Company, Bank of Montreal, as administrative agent, and other lenders party thereto were decreased from $530.0 million to $450.0 million, with the next such redetermination scheduled for spring 2020.

Joinder Agreement Amendment

In connection with the Merger, on August 6, 2019, Amplify Energy Operating LLC and Amplify Acquisitionco LLC entered into a Borrowing Base Redetermination, Commitment Increase and Joinder Agreement to Credit Agreement, with the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “Joinder Agreement”). The Joinder Agreement amended the Revolving Credit Facility to, among other things:

•

redetermine the borrowing base of the Revolving Credit Facility, by increasing the borrowing base from $425.0 million to $530.0 million;

•

increase the commitments of certain of the original lenders under the Revolving Credit Facility; and

•

add additional lenders as parties to the Revolving Credit Facility.

Upon closing of the Merger on August 6, 2019, Midstates’ existing reserve-based revolving credit facility was terminated, and all remaining borrowings were repaid by the Company.

F-30

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

First Amendment to Revolving Credit Facility

On May 5, 2019, OLLC entered into the First Amendment to Credit Agreement (the “First Amendment”), among OLLC, Acquisitionco, Amplify Energy, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent. (the “Administrative Agent”).

The First Amendment amended the Revolving Credit Facility to, among other things, (i) modify certain defined terms in connection with the completion of the transactions contemplated by the Merger Agreement, including the Merger; (ii) allow certain structural changes for tax planning activities; and (iii) modify certain covenants in the Revolving Credit Facility that restrict Amplify Energy’s ability to take certain actions or engage in certain business such that, once the First Amendment is effective, the occurrence of such actions or business in connection with the Merger Agreement or completion of the transactions contemplated thereby, including the Merger, will not be so restricted.

Certain of the modifications to the Revolving Credit Facility, including those permitting pre-Merger tax restrictions, became effective upon the signing of the First Amendment. The remaining modifications become effective concurrently with the consummation of the Merger, subject to certain closing conditions.

The First Amendment also contains customary representations, warranties and agreements of OLLC and the guarantors. All other material terms and conditions of the Revolving Credit Facility were unchanged by the First Amendment.

The foregoing description of the First Amendment is qualified in its entirety by reference to the First Amendment, which is attached as Exhibit 10.1 to Legacy Amplify’s current report on Form 8-K filed on May 6, 2019.

Second Amendment to Revolving Credit Facility

On July 16, 2019, OLLC entered into the Second Amendment to Credit Agreement (the “Second Amendment”), among OLLC, Acquisitionco, Amplify Energy, the guarantors party thereto, the lenders party thereto and the Administrative Agent.

The Second Amendment amended the parties’ existing Credit Agreement, dated as of November 2, 2018, in connection with the completion of the Merger, following which Midstates may contribute, through a series of transactions, the equity interests it holds in Midstates Petroleum Company, LLC, a Delaware limited liability company, to the borrower (the “Contribution”), to, among other things, (i) provide that if the Merger and the Contribution are not consummated on or prior to August 31, 2019, the Administrative Agent and the lenders have the right (but not the obligation) to redetermine the borrowing base on or after September 1, 2019 and (ii) amend certain other provisions of the Revolving Credit Facility.

The Second Amendment also contains customary representations, warranties and agreements of OLLC and the guarantors. All other material terms and conditions of the Revolving Credit Facility were unchanged by the Second Amendment.

The foregoing description of the Second Amendment is qualified in its entirety by reference to the Second Amendment, which is attached as Exhibit 10.1 to Legacy Amplify’s current report on Form 8-K filed on July 17, 2019.

Letter Agreement

On December 21, 2018, Legacy Amplify entered into a letter agreement relating to the New Credit Agreement (the “Letter Agreement”). Pursuant to the Letter Agreement, the parties to the New Credit Agreement agreed, among other things, to:

•

extend the date by which OLLC was required to show compliance with certain minimum hedging requirements set forth in the New Credit Agreement from December 31, 2018 to February 28, 2019; and

•

subject to certain conditions, waive the requirement that OLLC deliver to the Agent within 60 days after the closing date of the New Credit Agreement control agreements with respect to certain deposit accounts held or maintained by each Loan Party (as defined in the New Credit Agreement) on the closing date of the New Credit Agreement.

Emergence Credit Facility

On May 4, 2017, OLLC, as borrower, entered into the Amended and Restated Credit Agreement (the “Emergence Credit Agreement”) among Acquisitionco, as parent guarantor, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent. Pursuant to the Emergence Credit Agreement the lenders party thereto agreed to provide OLLC with the Emergence Credit Facility (the loans thereunder, the “Loans”).

F-31

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On November 2, 2018, in connection with our entrance into the Revolving Credit Facility, the Emergence Credit Facility was terminated and repaid in full. At December 31, 2018, $3.0 million of deferred financing costs related to the Emergence Credit Facility was written off resulting in a loss on extinguishment of debt.

Predecessor’s Revolving Credit Facility

Our Predecessor was a party to a $2.0 billion revolving credit facility, which was guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries).

On the Effective Date, the holders of claims under the Predecessor’s revolving credit facility received a full recovery, which included a $24.8 million pay down and their pro rata share of the Emergence Credit Facility. See Note 2 for additional information.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented:

Successor

Predecessor

For the

Period from

Year Ended

December 31,

through

2019

2018