Alta Mesa Resources (AMRWW) 10-K2019 FY Annual report

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

As described further in Item 8 of this Annual Report, the Business Combination was consummated on February 9, 2018, that resulted in our acquisition of interests in Alta Mesa, Alta Mesa GP and KFM through a newly formed subsidiary, SRII Opco. Prior to the Business Combination, Alta Mesa was controlled by High Mesa, Inc. (“HMI”).

Immediately prior to the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and liabilities to High Mesa Holdings, LP (“High Mesa”), such that Alta Mesa’s only remaining oil and gas assets and liabilities were located in the STACK. As described elsewhere, High Mesa owes us a substantial sum for amounts arising before and after the Business Combination, and it had indemnified us for liabilities arising from non-STACK oil and gas assets. We believe there is substantial doubt about its ability to make payment and honor its indemnification given HMI’s filing for bankruptcy protection in January 2020. Information related to Alta Mesa’s non-STACK oil and gas assets and liabilities that were sold or distributed is disclosed as discontinued operations in Item 8 of this Annual Report.

Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values and pushed those values down to the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods - the period before the Business Combination on February 9, 2018 (“Predecessor”) and the period after the Business Combination (“Successor”).

Our Upstream segment sells our production of oil, natural gas and NGLs to customers generally at prevailing spot prices in effect at the time of the sale. Our Midstream segment derives its revenue from fees assessed for gathering and processing natural gas, gathering and transporting oil, the sale of processed residue gas and NGLs and produced water gathering and disposal services. Natural gas is processed on behalf of the producer and the resulting gas, condensate and NGLs are sold at market prices. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense. Collateral or other security is generally not required with regard to our trade receivables.

During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC (“ARM”) marketed our oil, gas and NGLs for a marketing fee that was deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. In June 2019, we terminated our oil and NGL marketing agreement with ARM and began marketing such products internally.

For 2019, ARM marketed $123.0 million, or 24.6% of our total operating revenue for the period.

Other than our natural gas marketing agreement with ARM, we had one customer, Phillips 66, that accounted for $202.6 million, or 40.5% of our total operating revenue for 2019.

Weather conditions affect the demand for, and prices of, oil and gas. During the winter, natural gas demand for heating by residential and commercial consumers generally increases whereas high summer temperatures can result in an increase in demand from the power sector. Natural gas in storage typically increases from April through October. Crude oil markets tend to be stronger in the fourth quarter when demand for heating oil is impacted by colder weather and inventory build. Hurricanes and other severe weather (particularly along the Gulf Coast) can also impact supplies by causing disruptions in the level of oil and gas production. Due to these fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

We compete with other companies in all areas of our operations, including, in the past, the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies and independent oil and gas companies. Many of our competitors are large, well-established companies with substantially greater resources and better credit than us and have been engaged in the oil and gas business for a longer period of time than we have. Our filings for bankruptcy protection and restrictions placed on our spending by the Bankruptcy Court have also put us at a competitive disadvantage. This may allow our competitors to have an advantage over us with respect to:

In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe, materials (including drilling and completion fluids) and personnel. We are unable to predict when, or if, such future shortages will occur or their impact on our operations.

Our Upstream and Midstream operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental agencies, including 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 actions. Among other things, these laws and regulations may:

These laws, rules and regulations often impose difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in remedial or corrective action obligations.

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of non-hazardous and hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. As part of our operations, we generate some amounts of ordinary industrial wastes that may be deemed as hazardous wastes by regulatory authorities. Drilling fluids, produced waters, and most of the other wastes associated with our operations, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that regulations could change and cause wastes now classified as non-hazardous to be classified as hazardous wastes.

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability on classes of persons considered to be responsible for the release of hazardous substances and other classes of materials. Under CERCLA, such persons may be subject to joint and several, strict liability for costs of investigation and remediation and for damages without regard to fault or legality of the original conduct. These classes of persons, referred to as potentially responsible parties (“PRPs”), include the current and past owners or operators of a site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable statutes.

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state and federal 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. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

Our underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state and local laws and regulations. The UIC program includes administrative requirements for produced water disposal and prohibits migration of fluid containing any contaminant into underground sources of drinking water. State regulations require permits to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of

liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.

Furthermore, in response to recent seismic events near produced water disposal wells, federal and some state agencies are investigating whether such wells have contributed to increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations.

Our operations on federal lands may be subject to the federal National Environmental Policy Act (“NEPA”), which requires federal agencies, including the EPA, to evaluate major agency actions having the potential to significantly impact the environment. As part of such evaluations, an agency will conduct an environmental assessment that assesses the potential impacts of a proposed project and may require the preparation of a detailed environmental impact statement for public review and comment. Our current and future operations on federal lands will be subject to NEPA, which could delay or impose additional conditions and costs on us. Moreover, this process could involve protest, appeal or litigation, any or all of which may impact our operations.

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes enacted to protect the health and safety of workers. In addition, comparable state statutes require that we organize and/or disclose information about hazardous materials attendant to our operations to our employees, state and local governmental authorities and citizens.

Our processing plant operations are also subject to standards designed to ensure the safety of our processes, such as the Occupational Safety and Health Administration’s Process Safety Management standard, which is designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The Process Safety Management standard imposes requirements on regulated entities related to managing these hazards. These requirements include conducting process hazard analyses for processes involving highly hazardous chemicals, developing detailed written operating procedures, including procedures for managing change, and evaluating the mechanical integrity of critical equipment. We conduct periodic audits of Process Safety Management systems at each of our locations subject to this standard.

We perform hydraulic fracturing in horizontally drilled wells. Currently, most of our hydraulic fracturing activities are regulated at the state level, given that the EPA only has limited authority to regulate fracturing activities. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater into surface waters; and disposal or storage of fracturing wastewater in unlined pits.

Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and regulations that restrict the emission of air pollutants. These laws and regulations may require us to obtain approval for the construction or modification of certain facilities expected to produce or significantly increase air emissions, comply with stringent air permitting requirements and also utilize equipment or technologies to control emissions. Obtaining such permits could delay our operations.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at all levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.

Federal agencies also directly regulate emissions of methane, a GHG, from oil and gas operations. In August 2016, the EPA issued a final New Source Performance Standards (“NSPS”) rule, known as Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and gas sector to reduce methane gas and volatile organic compound emissions. These Subpart OOOOa standards expanded the previously issued NSPS published by the EPA in 2012, and known as Subpart OOOO, by using certain equipment-specific emissions control practices. However, in August 2019, the EPA proposed two options for further rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for volatile organic compounds, and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural gas category the natural gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the Subpart OOOOa standards applicable to all oil and natural gas sources, without removing any sources from that source category (and still requiring control of volatile organic compounds in general). Future implementation of this rule is uncertain at this time.

Our operations are also subject to various other types of regulation at the federal, state and local level. These types of regulations include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate may also regulate:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. We rely upon the Oklahoma “forced pooling” process to facilitate working interest owners’ participation in our operations.  Under this process, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may initiate “forced pooling”. Under current regulations, drilling and spacing units for our targeted horizons are based on a maximum of four to eight horizontal wells, depending on the formation, on a 640-acre section. In a forced pooling action, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission (“OCC”) and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair value of the mineral interests in the unit is determined in an administrative proceeding by reference to market transactions involving nearby oil and gas rights, including nearby mineral lease costs.

Assuming the application for a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair value for their interest, usually in the form of a cash payment, an overriding royalty, or some

combination, based on the fair value established and approved through the administrative hearing. The pooling order typically addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

The availability of forced pooling normally means that it is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Oil and gas companies in Oklahoma generally attempt to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.

The gross production tax, or severance tax, is a value-based tax levied at a basic rate of 7% upon the production of oil and gas in Oklahoma. As an economic incentive to develop its resources, Oklahoma has historically offered a “tax holiday” with rates ranging from 1% for 48 months to 2% for 36 months for production from horizontal wells. Through June 2018, Oklahoma imposed a tax of 2% of gross production for the first 36 months of production and then at 7% thereafter on wells drilled after July 1, 2015. Effective July 2018, the 2% tax rate was increased to 5% for wells drilled after July 1, 2015 that were still within their first 36 months of production. For the period beyond 36 months, the tax rate remains at 7% for the remaining productive life of each well. All wells drilled after July 1, 2018 are taxed at 5% of gross production for the first 36 months of production and then at 7% thereafter. In addition, a longstanding excise tax of 0.095% continues to be levied.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations covering these procedures. Some state agencies and municipalities have binding requirements related thereto.

The rates, terms and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the Federal Energy Regulatory Commission (the “FERC”), as common carriers, under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In March 2016, the PHMSA issued a Notice of Proposed Rulemaking proposing to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines, including both high consequence areas (“HCAs”) and non-HCAs. In October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines, and enhanced emergency order procedures. The gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA is expected to issue the second and third parts of the gas Mega Rule in the near future. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety.

Any transportation of our crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA, and the DOT’s Federal Railroad Administration (“FRA”)

under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.

Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation by the FERC under the NGA. We believe that our Midstream assets meet the tests the FERC has used to determine exemption from its jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.

The oil and gas industry is also subject to other federal, state and local regulations and laws relating to resource conservation and employment standards.

As of December 31, 2019, we had 151 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

We regularly execute master services contracts with our third-party vendors, suppliers and contractors in which they agree to indemnify us for injuries and deaths of their employees and contractors. Similarly, we generally agree to indemnify them against claims made by our other vendors, suppliers, contractors and employees. Additionally, each party is generally responsible for damage to its own property.

 

As of December 31, 2019, we held a highly contiguous position of approximately 127,100 net acres in the up-dip, naturally-fractured oil portion of the STACK, primarily in eastern Kingfisher and south-eastern Major Counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. This position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet.

At December 31, 2019, we had an average 66% net working interest in 814 gross producing wells.

In January 2016, we entered into a joint development agreement (as subsequently amended, the “JDA”) with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City Management, LLC, to fund a portion of our drilling operations with the intent to accelerate our development. The JDA established a development plan of 60 wells in three tranches, and provided opportunities for the parties to potentially agree to an additional 20 wells. As of December 31, 2019, 61 joint wells had been drilled or spudded.

Under the JDA, up to 100% of our well costs could be funded up to a specified total well cost. In exchange for BCE carrying the drilling and completion costs, they received 80% of our working interest in each funded well until attaining a 15% internal rate of return for the entire tranche, at which time their interest reduces to 20%. If a tranche attains a 25% internal rate of return, their interest reduces to 12.5%.

During the 2018 Successor Period, we brought 25 horizontal wells on production that were funded through the JDA. At December 31, 2019, there were no JDA wells in progress, and none have been developed in 2020. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves. The JDA expired in January 2020 pursuant to its terms.

Our proved reserves and production profile as of December 31, 2019 was as follows:

Key information and assumptions used in determining our estimated net proved reserves at the end of each period is set forth in Item 8. All of our reserves are located in the United States.

Based on Alta Mesa’s bankruptcy filing and/or our inability to fund development costs, we did not recognize any PUDs as of December 31, 2019 and 2018. The information presented during the 2018 Predecessor Period includes amounts related to discontinued operations. Changes in our proved undeveloped reserves during the 2018 Successor Period and the 2018 Predecessor Period were (in MBoe):

Our policies and practices regarding internal controls over reserve recognition are structured to objectively and accurately estimate our oil and gas reserves quantities and their present value in compliance with SEC standards.  The reserve estimation process begins with our Corporate Reserves department, which gathers and analyzes much of the data used as inputs to estimating reserves. Working and net revenue interests are sourced from our division order system in our land department.  Lease operating expenses are provided by our accounting department and our operations team provides capital expenses.  Our Vice President of Planning and Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and volumetric analysis, with performance methods preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on analogy to offset production in the same area.

We maintain internal controls that we believe result in the proper amount and value of our reported reserves. These controls, which we determined to be effective for all periods presented, include:

Ryder Scott Company, LP (“Ryder Scott”), a third-party petroleum engineering consulting firm, audited approximately 97% of our 2019 proved reserves on a 6:1 Mcf per Bbl conversion basis. Their report is filed with this Annual Report as Exhibit 99.1. The reserve audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Miles R. Palke with Ryder Scott earned a B.S. in Petroleum Engineering from Texas A&M University in College Station, Texas and a Master of Science in Petroleum Engineering from Stanford University in Palo Alto California.  Mr. Palke graduated Magna Cum Laude and with University Honors from Texas A&M University and is a registered Professional Engineer in the State of Texas.  Based on his educational background, professional training and more than 23 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Palke has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.

A reserves audit and a financial audit are separate activities with unique and different processes and results. A reserves audit under SEC standards is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.

Information relating to our oil and gas production, sales prices for our products produced and production costs is included in Item 7.

At December 31, 2019, we had no wells that were in progress for drilling or completion operations.

Information about our firm transportation commitments is included in Part II, Item 8.

The following sets forth information with respect to our wells and acreage under lease as of December 31, 2019, all of which is located in the United States:

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We typically conduct a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, at the time we acquire properties. We believe that title to our interests is satisfactory and consistent with the standards in our industry.

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

On September 12, 2019, an adversary proceeding was commenced by certain of the AMH Debtors against KFM, Oklahoma Produced Water Solutions, LLC, SRII Opco, HMI, Michael E. Ellis, and Harlan H. Chappelle (together, the “Defendants”), alleging, among other things, that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and KFM and its subsidiaries could be rejected, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the Defendants breached their respective fiduciary duties owed to the AMH Debtors by entering related-party crude oil and gas gathering agreements, which as a result are subject to rescission, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. Pursuant to the adversary proceeding complaint, AMH is seeking declaratory judgements that the gathering agreements cannot continue to burden AMH or its estates and could therefore be rejected or avoided under the Bankruptcy Code. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants.

On December 6, 2019, the Bankruptcy Court held that the dedication provisions of the crude oil, gas and water gathering agreements “ran with the land” and therefore could not be rejected under the Bankruptcy Code, granting summary judgment in favor of the defendants on that count of the complaint.  All other counts were reserved for trial, which commenced on December 9, 2019, but was subsequently stayed by the Bankruptcy Court at the request of the parties.  The litigation remains stayed as of the date hereof.

Additional information relating to the formation of the Company and the acquisition of Alta Mesa and KFM on February 9, 2018, may be found in Item 8. Immediately prior to the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa. We have reported these distributed assets as discontinued operations for all periods presented.

Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values on the closing date, including recording the fair values in the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods, the period before the Business Combination (“Predecessor Period”) and the period after the Business Combination (“Successor Period”). The Company’s financial statement presentation reflects Alta Mesa as the “Predecessor” for periods prior to February 9, 2018. The Company, including the consolidated results of Alta Mesa and Kingfisher, is the “Successor” for periods since February 9, 2018.

Accordingly, for purposes of explaining our segment results, we have presented the 2019 results with the 2018 Successor Period and the 2018 Predecessor Period results of Alta Mesa, our Upstream segment. As KFM, our Midstream segment, was acquired on February 9, 2018, our discussion of our Midstream segment results covers the 2019 results and the 2018 Successor Period results.

As noted above, the Initial Debtors filed for bankruptcy protection in September 2019 and the Additional Debtors filed for bankruptcy protection in January 2020. As a result of our bankruptcy filings and previous restrictions by our lenders on our ability to access additional capital, our ability to incur the levels of spending necessary to continue to develop our upstream properties and expand our midstream operations were significantly restricted. This negatively impacted our future drilling plans and our expectations regarding production levels, which contributed to lower throughput expectations for our midstream processing assets. In addition, the Sale Transactions reflect prices of $232.0 million for substantially all of the upstream properties and assets and $88.0 million for our midstream assets. As these prices were below the carrying value of the respective assets, we adjusted our carrying values down to the expected sales prices, after estimated direct sales costs, as we believe the Buyer has the intent and ability to close the Sale Transactions.

Additionally, as a result of the expected sales of our assets described above and our expectations of contracts that will be rejected in bankruptcy, we also recognized impairments of our operating lease right-of-use assets and a long-term prepaid asset due to our inability to recover the carrying value of these assets.

The Company’s management believes Adjusted EBITDAX and Adjusted EBITDA are useful because they allow users to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDAX and Adjusted EBITDA should not be considered as an alternative to our segments’ net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.  The Company’s applicable corporate activities have also been allocated to the supported business segments.

Interest income on the promissory notes amounted to approximately $0.9 million and $0.1 million for the 2018 Successor Period and the 2018 Predecessor Period, respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019.

Drilling and field activities require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. As such, actual results may materially differ from predicted results, which could lower production and net undiscounted cash flows.

Item 8. Financial Statements and Supplementary Data

To the Stockholders and Board of Directors

Alta Mesa Resources, Inc.:

We have audited the accompanying consolidated balance sheets of Alta Mesa Resources, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (Successor), changes in partners’ capital (Predecessor) and cash flows for the year ended December 31, 2019, the period from February 9, 2018 to December 31, 2018 (Successor), and the period from January 1, 2018 to February 8, 2018 (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 period from February 9, 2018 to December 31, 2018 (Successor), and the period from January 1, 2018 to February 8, 2018 (Predecessor), in conformity with U.S. generally accepted accounting principles.

We have served as the Company’s auditor since 2018.

Houston, Texas