ITEM 1.
BUSINESS
References
On August 6, 2019, Midstates Petroleum Company, Inc., a Delaware corporation (“Midstates”), completed its business combination (the “Merger”) with Amplify Energy Corp., a Delaware corporation (“Legacy Amplify”), in accordance with the terms of that certain Agreement and Plan of Merger, dated May 5, 2019 (the “Merger Agreement”), by and among Midstates, Legacy Amplify and Midstates Holdings, Inc., a Delaware corporation and direct, wholly owned subsidiary of Midstates (“Merger Sub”). Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates, and immediately following the Merger, Legacy Amplify merged with and into Alpha Mike Holdings LLC, a Delaware limited liability company and wholly owned subsidiary of Midstates (“LLC Sub”), with LLC Sub surviving as a wholly owned subsidiary of Midstates. On the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.” (the “Company”) and LLC Sub changed its name to “Amplify Energy Holdings LLC.”
For financial reporting purposes, the Merger represented a “reverse merger” and Legacy Amplify was deemed to be the accounting acquirer in the transaction. Legacy Amplify’s historical results of operations replaced Midstates’ historical results of operations for all periods prior to the Merger and, for all periods following the Merger, the Company’s financial statements reflect the results of operations of the combined company. Accordingly, the financial statements for the Company included in this Annual Report for periods prior to the Merger are not the same as Midstates prior reported filings with the SEC, which were derived from the operations of Midstates. The results of any one quarter should not be relied upon as an indication of future performance.
When referring to Legacy Amplify, the intent is to refer to Amplify Energy Corp. prior to the Merger, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Legacy Amplify is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to “Predecessor” or the “Company” in reference to the period prior to the 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.
Overview
Amplify Energy is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment, as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas/North Louisiana, and South Texas. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs.
Beginning in 2019, the Company has elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The change in presentation reflects our liquids-weighted production and reserve profile with a balanced approach to development of our oil and natural gas asset portfolio.
The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. As of December 31, 2019:
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Our total estimated proved reserves were approximately 163.0 MMBoe, of which approximately 43% were oil and 80% were classified as proved developed reserves;
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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
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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.
Legacy Amplify was formed in March 2017 in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from December 2011 to May 2017. As discussed further in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 of the Notes to the Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, 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 U.S. 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 (the “Confirmation 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 the Company emerged from bankruptcy.
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’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 (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
On January 30, 2020, Richard P. Smiley notified the Company of his intent to resign from his current position as Senior Vice President, Operations. Mr. Smiley intends to remain in his role at the Company to assist with an orderly transition of his responsibilities. Mr. Smiley did not resign from the position of Senior Vice President, Operations due to any disagreement with the Company or any matter relating to the Company’s operations, policies or practices.
Properties
We engaged Cawley, Gillespie and Associates, Inc. (“CG&A”), our independent reserve engineers, to prepare our reserves estimates for all of our proved reserves (by volume) at December 31, 2019. The following table summarizes information, based on a reserve report prepared by CG&A (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2019 and our average net production for the three months ended December 31, 2019:
(1)
Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)
Standardized measure is calculated in accordance with Accounting Standards Codification, or ASC, Topic 932, Extractive Activities-Oil and Gas, and is calculated using SEC pricing, before market differentials, of $55.69/Bbl for crude oil and NGLs and $2.58/MMBtu for natural gas.
(3)
The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2019 by the annualized average net production for the three months ended December 31, 2019.
(4)
South Texas region properties include wells and properties in fields located primarily in the Eagle Ford and Eagleville as of December 31, 2019.
Our Areas of Operation
Oklahoma
Approximately 37% of our estimated proved reserves as of December 31, 2019 and approximately 34% of our average daily net production for the three months ended December 31, 2019 were located in the Oklahoma region. Our Oklahoma properties include wells and properties primarily located in Alfalfa and Woods counties in Oklahoma. Those properties collectively contained 59.7 MMBoe of estimated net proved reserves as of December 31, 2019 based on our reserve report and generated average net production of 10.1 MBoe/d for the three months ended December 31, 2019.
Rockies
Approximately 22% of our estimated proved reserves as of December 31, 2019 and approximately 14% of our average daily net production for the three months ended December 31, 2019 were located in the Rockies region. Our Rockies properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Rockies properties contained 36.5 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2019 based on our reserve report and generated average net production of 4.1 MBoe/d for the three months ended December 31, 2019.
California
Approximately 13% of our estimated proved reserves as of December 31, 2019 and approximately 10% of our average daily net production for the three months ended December 31, 2019 were located in federal waters offshore Southern California. These properties (the “Beta properties”) consist of: 100% of the working interests and currently 75.2% average net revenue interest in three Pacific Outer Continental Shelf lease blocks (P-0300, P-0301 and P-0306), referred to as the Beta Unit, in the Beta Field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. Our Beta properties contained 20.3 MMBbls of estimated net proved oil reserves as of December 31, 2019 based on our reserve report. Oil and gas are produced from the Beta Unit via two production platforms, referred to as the Ellen and Eureka platforms, equipped with permanent drilling rigs and associated equipment. On a third platform, Elly, the oil, water and gas are separated, and the oil is prepared for sale, while the gas is burned as fuel for power and the water is recycled back into the reservoir for pressure maintenance. Sales quality oil is then pumped from the Elly platform to the Beta Pump Station located onshore at the Port of Long Beach, California via a 16-inch diameter oil pipeline, which extends approximately 17.5 miles. Amplify Energy’s wholly owned subsidiary, San Pedro Bay Pipeline Company, owns and operates the pipeline system.
East Texas / North Louisiana
Approximately 26% of our estimated proved reserves as of December 31, 2019 and approximately 39% of our average daily net production for the three months ended December 31, 2019 were located in the East Texas/ North Louisiana region. Our East Texas/ North Louisiana properties include wells and properties primarily located in the Joaquin, Carthage, Willow Springs and East Henderson fields in East Texas. Those properties collectively contained 42.7 MMBoe of estimated net proved reserves as of December 31, 2019 based on our reserve report and generated average net production of 11.5 MBoe/d for the three months ended December 31, 2019.
South Texas
Approximately 2% of our estimated proved reserves as of December 31, 2019 and approximately 3% of our average daily net production for the three months ended December 31, 2019 were located in the South Texas region. Our South Texas properties include wells and properties in fields located primarily in the Eagle Ford and Eagleville fields. Our South Texas properties contained 3.8 MMBoe of estimated net proved reserves as of December 31, 2019 based on our reserve report. Those properties collectively generated average net production of 1.0 MBoe/d for the three months ended December 31, 2019. In May 2018, we closed a transaction to divest certain of our non-core assets located in South Texas (the “South Texas Divestiture”).
Our Oil and Natural Gas Data
Our Reserves
Internal Controls. Our proved reserves were estimated at the well or unit level for reporting purposes by CG&A, our independent reserve engineers. The Company maintains internal evaluations of our reserves in a secure reserve engineering database. CG&A interacts with the Company’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data to prepare the Company’s proved reserves report. Reserves are reviewed and approved internally by our senior management on an annual basis and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our Revolving Credit Facility. Our reserve estimates are prepared by CG&A at least annually.
Our internal professional staff works closely with CG&A to ensure the integrity, accuracy and timeliness of data that is furnished to them in order to prepare the reserves report. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide CG&A other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their preparation of our reserves.
Qualifications of Responsible Technical Persons
Internal Engineers. Tony Lopez is the technical person at the Company primarily responsible for overseeing and providing oversight of the preparation of the reserves estimates with our third-party reserve engineers.
Mr. Lopez has over 15 years of corporate reserve reporting experience. Most recently Mr. Lopez was Vice President of Acquisitions and Engineering for EnerVest, Ltd., where he managed the corporate reserve reporting process and the financial planning & analysis department. Prior to that, Mr. Lopez was Manager of Reservoir Engineering for EnerVest’s Eastern Division. Mr. Lopez is a graduate of West Virginia University and holds a B.S. in Petroleum and Natural Gas Engineering. Mr. Lopez is an active member of the Society of Petroleum Engineers.
Cawley, Gillespie and Associates, Inc. CG&A is an independent oil and natural gas consulting firm. No director, officer, or key employee of CG&A has any financial ownership in us or any of our affiliates. CG&A’s compensation for the preparation of its report is not contingent upon the results obtained and reported. CG&A has not performed other work for us or any of our affiliates that would affect its objectivity. The estimates of our proved reserves presented in the CG&A reserve report were overseen by Todd Brooker.
Mr. Brooker is the President of CG&A and has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron Corporation. Mr. Brooker’s experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.
Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
Estimated Proved Reserves
The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure associated with the estimated proved reserves attributable to our properties as of December 31, 2019, based on the prepared reserve report by CG&A, our independent reserve engineers. The standardized measure shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.
(1)
Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)
Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest expense, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions. For a description of our commodity derivative contracts, see “Item 1. Business - Operations - Derivative Activities” as well as “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Commodity Derivative Contracts.”
(3)
Our estimated net proved reserves and related standardized measure were determined using 12-month trailing average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month in effect as of the date of the estimate, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, see “Item 1A.
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.
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.
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;
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our limited trading history subsequent to our emergence from the Chapter 11 Cases;
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our limited trading volume;
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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;
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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.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
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.
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.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
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:
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$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.
(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.
ITEM 6.
SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with “Item 7.
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.
Beginning in 2019, the Company has elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The change in presentation reflects our liquids-weighted production and reserve profile with a balanced approach to development of our oil and natural gas asset portfolio.
The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. As of December 31, 2019:
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Our total estimated proved reserves were approximately 163.0 MMBoe, of which approximately 43% were oil and 80% were classified as proved developed reserves;
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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
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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
On January 30, 2020, Richard P. Smiley notified the Company of his intent to resign from his current position as Senior Vice President, Operations. Mr. Smiley intends to remain in his role at the Company to assist with an orderly transition of his responsibilities. Mr. Smiley did not resign from the position of Senior Vice President, Operations due to any disagreement with the Company or any matter relating to the Company’s operations, policies or practices.
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:
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.
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:
The following table summarizes our derivative contracts as of December 31, 2018 and the average prices at which the production was hedged:
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:
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.
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 of this Annual Report and are incorporated herein by reference.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
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.
ITEM 9B.
OTHER INFORMATION
None
PART III
ITEM 10.
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.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to the Proxy Statement.
ITEM 12.
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.
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.
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.
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 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
*
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.
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.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
AMPLIFY ENERGY CORP.
Page No.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018
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)
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)
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)
Notes to Consolidated Financial Statements
Note 1 - Organization and Basis of Presentation
Note 2 - Emergence from Voluntary Reorganization under Chapter 11
Note 3 - Fresh Start Accounting
Note 4 - Summary of Significant Accounting Policies
Note 5 - Revenues
Note 6 - Acquisitions and Divestitures
Note 7 - Fair Value Measurements of Financial Instruments
Note 8 - Risk Management and Derivative Instruments
Note 9 - Asset Retirement Obligations
Note 10 - Restricted Investments
Note 11 - Debt
Note 12 - Equity (Deficit)
Note 13 - Earnings per Share/Unit
Note 14 - Equity-based Awards
Note 15 - Leases
Note 16 - Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Note 17 - Related Party Transactions
Note 18 - Commitments and Contingencies
Note 19 - Income Tax
Note 20 - Quarterly Financial Information (Unaudited)
Note 21 - Supplemental Oil and Gas Information (Unaudited)
Note 22 - Subsequent Events
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
AMPLIFY ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In thousands, except outstanding shares)
See Accompanying Notes to Consolidated Financial Statements.
AMPLIFY ENERGY CORP.
STATEMENTS OF CONSOLIDATED OPERATIONS
(In thousands, except per share/unit amounts)
See Accompanying Notes to Consolidated Financial Statements.
AMPLIFY ENERGY CORP.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(In thousands)
See Accompanying Notes to Consolidated Financial Statements.
*See Note 1 for information regarding recast amounts and basis of financial statement presentation.
AMPLIFY ENERGY CORP.
STATEMENTS OF CONSOLIDATED EQUITY (PREDECESSOR)
(In thousands)
AMPLIFY ENERGY CORP.
STATEMENTS OF CONSOLIDATED EQUITY (SUCCESSOR)
(In thousands)
See Accompanying Notes to Consolidated Financial Statements.
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”).
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.
Beginning in 2019, the Company has elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The change in presentation reflects our liquids-weighted production and reserve profile with a balanced approach to development of our oil and natural gas asset portfolio.
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:
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.
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.
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):
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.
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.
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.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2)
Reflected the changes in cash and cash equivalents, including the following (in thousands):
(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):
(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):
(10)
Net increase in our stockholders’/partners’ equity reflects the following (in thousands):
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:
(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):
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.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
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.
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.
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.
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.
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
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. See Note 9 for further discussion of 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
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. No significant imbalances existed at December 31, 2019 and 2018.
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:
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.
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.
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.
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):
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.”
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.
(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.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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:
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.
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.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 2019, the Company had the following open commodity positions:
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:
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.
(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):
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):
(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
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. The components of the restricted investment balances are as follows:
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:
(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.
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.
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”).
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:
Senior Notes
On April 17, 2013, May 23, 2013 and October 10, 2013, our Predecessor and Finance Corp. (collectively, the “Issuers”) issued $300.0 million, $100.0 million and $300.0 million, respectively, of the 2021 Senior Notes. The 2021 Senior Notes were fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain subsidiaries of the Predecessor. The 2021 Senior Notes would have matured on May 1, 2021 with interest accruing at a rate of 7.625% per annum and were payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were governed by an indenture and were subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any.
On July 17, 2014, the Issuers completed a private placement of $500.0 million aggregate principal amount of the 2022 Senior Notes. The 2022 Senior Notes were issued at 98.485% of par and were fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain subsidiaries of the Predecessor. The 2022 Senior Notes would have matured on August 1, 2022 with interest accruing at 6.875% per annum and were payable semi-annually in arrears on February 1 and August 1 of each year. The 2022 Senior Notes were governed by an indenture and were subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any.
The Company’s voluntary petitions as described in Note 2 constituted an event of default that accelerated the obligations under the Notes. For the period from January 17, 2017 through May 4, 2017 our contractual interest that was not recorded on the Notes was approximately $24.2 million.
On the Effective Date, the Notes were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received their pro rata share of the New Common Shares. Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.
Letters of credit
At December 31, 2019, we had $1.7 million letters of credit outstanding, all related to operations at our Wyoming properties.
Unamortized Deferred Financing Costs
Unamortized deferred financing costs associated with our Revolving Credit Facility was $4.7 million at December 31, 2019. The unamortized deferred financing costs are amortized over the remaining life of our Revolving Credit Facility using the straight-line method which generally approximate the effective interest method.
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. The remaining deferred financing costs of $3.0 million was written off resulting in a loss on extinguishment of debt.
Note 12. Equity (Deficit)
Equity Outstanding
The Company’s authorized capital stock includes 250,000,000 shares of common stock, $0.01 par value per share. The following table summarizes the changes in the number of outstanding common units and shares of common stock:
(1)
Restricted common units were generally net-settled by our Predecessor unitholders to cover the required withholding tax upon vesting. The Predecessor unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were less than approximately $0.1 million for the period from January 1, 2017 through May 4, 2017. These net-settlements had the effect of unit repurchases by the Company as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Emergence from Legacy Amplify Bankruptcy
In accordance with the Plan, on the Effective Date:
•
Legacy Amplify issued 25,000,000 New Common Shares and Warrants to purchase up to 2,173,913 shares of its common stock;
•
the Predecessor common units were cancelled; and
•
each Predecessor 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.
On the Effective Date, there were 25,000,000 New Common Shares issued and outstanding.
Treasury Stock
As of August 5, 2019, Midstates had 205,861 treasury shares outstanding. After the Merger closed, the Company retired and cancelled all treasury stock outstanding. No treasury stock remained outstanding at December 31, 2019.
Warrants
On the Effective Date, Legacy Amplify entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent (“AST”), pursuant to which Legacy Amplify issued Warrants to purchase up to 2,173,913 shares of Legacy Amplify’s common stock (representing 8% of Legacy Amplify’s outstanding common stock as of the Effective Date including shares of Legacy Amplify’s common stock issuable upon full exercise of the Warrants, but excluding any common stock issuable under the MIP), exercisable for a five year period commencing on the Effective Date at an exercise price of $42.60 per share.
The fair values for the warrants upon issuance on the Effective Date have been estimated using the Black-Scholes option pricing model using the following assumptions:
On the effective date of the Merger, Legacy Amplify, Midstates and AST entered into an Assignment and Assumption Agreement, pursuant to which the Company agreed to assume Legacy Amplify’s Warrant Agreement.
As of August 5, 2019, Midstates had outstanding warrants of 4,647,520 Third Lien Notes Warrants at an exercise price of $22.78 per share (the “Third Lien Warrants”) and 2,332,089 Unsecured Creditor Warrants at an exercise price of $43.67 per share (the “Unsecured Creditor Warrants” and collectively with the Third Lien Warrants, the “ Midstates Warrants”). The Midstates Warrants expire on April 21, 2020. As a result of the Merger, the value of the outstanding Midstates Warrants was adjusted downward based on the low stock price and estimated fair value as of the Merger date. See Note 6 for additional information regarding the purchase price allocation of the Merger.
Share Repurchase Program
On December 21, 2018, Legacy Amplify’s board of directors authorized the repurchase of up to $25.0 million of Legacy Amplify’s outstanding shares of common stock, with repurchases to begin on or after January 9, 2019. During the six months ended June 30, 2019, Legacy Amplify repurchased 169,400 shares of common stock at an average price of $7.35 per share for a total cost of approximately $1.3 million. On April 18, 2019, in anticipation of the Merger, Legacy Amplify terminated the repurchase program.
In connection, with the closing of the Merger, the board of directors approved the commencement of an open market share repurchase program of up to $25.0 million of the Company’s outstanding shares of common stock, with repurchases beginning on or after August 6, 2019. For the period from August 6, 2019 to December 31, 2019, the Company repurchased 4,195,247 shares of common stock at an average price of $6.28 per share for a total cost of approximately $24.9 million.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Dividend Payment
On November 5, 2019, our board of directors approved a dividend of $0.20 per share of outstanding common stock or $7.7 million in aggregate, which was paid on December 18, 2019, to stockholders of record at the close of business on December 4, 2019.
On August 6, 2019, our board of directors approved a dividend of $0.20 per share of outstanding common stock or $8.2 million in aggregate, which was paid on September 18, 2019, to stockholders of record at the close of business on September 4, 2019.
The amount of future dividends is subject to discretionary approval by the board of directors.
Tender Offer
On November 19, 2018, Legacy Amplify’s board of directors announced the commencement of a tender offer to purchase 2,916,667 shares of Legacy Amplify’s common stock. On December 19, 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated November 19, 2018, as amended, Legacy Amplify repurchased an aggregate of 2,916,667 shares of Legacy Amplify common stock at a price of $12.00 per share, for a total cost of approximately $35.0 million (excluding fees and expenses relating to the offer).
Note 13. Earnings per Share/Unit
The following sets forth the calculation of earnings (loss) per share/unit, or EPS/EPU, for the periods indicated (in thousands, except per unit amounts):
(1)
Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.
(2)
Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.
Note 14. Equity-based Awards
Merger Impact
As of August 6, 2019, each outstanding share of Legacy Amplify common stock, par value $0.0001 per share, available for issuance under the Amplify Energy Corp. 2017 Non-Employee Directors Compensation Plan (the “Legacy Amplify Non-Employee Directors Compensation Plan”) and the Amplify Energy Corp. Management Incentive Plan (the “Legacy Amplify MIP” and, together with the Legacy Amplify Non-Employee Directors Compensation Plan, the “Legacy Amplify Plans”) was converted and assumed by the Company and will be available for future issuance under the Legacy Amplify Plans in satisfaction of the vesting, exercise or other settlement of options and other equity awards that may be granted by the Company following the close of the Merger (after conversion of such shares and appropriate adjustment to reflect the terms of the Merger Agreement).
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 table below shows the activity related to the Legacy Amplify MIP prior to and after the closing of the Merger, which reflects the conversion of outstanding and unvested equity awards.
Legacy Amplify MIP awards are granted in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance awards, stock awards and other incentive awards. To the extent that an award under the Legacy Amplify MIP is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for future grants under the Legacy Amplify MIP. The Legacy Amplify MIP is administered by the board of directors of the Company. At December 31, 2019, 626,404 shares remain available for issuance under the Legacy Amplify MIP.
On October 21, 2016, Midstates established the 2016 Long-term Incentive Plan (“Midstates 2016 LTIP”) shares for issuance under the terms of the Midstates 2016 LTIP to employees and directors. The types of awards that may be granted under the Midstates 2016 LTIP include stock options, restricted stock units, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock, as well as certain cash-based awards. To the extent that an award under the Midstates 2016 LTIP is expired, forfeited or are cancelled for any reason without having been exercised in full, the unexercised award would then be available again for future grants under the Midstates 2016 LTIP. After the effective date of the Merger, the Midstates 2016 LTIP shares are available for issuance to employees and directors of the Company. At December 31, 2019, 2,004,934 shares remain available for issuance under the Midstates 2016 LTIP.
Restricted Stock Units
Restricted Stock Units with Service Vesting Condition
Restricted stock units with service vesting conditions (“TSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with TSUs was $0.8 million at December 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.8 years.
The following table summarizes information regarding the TSUs granted under the Legacy Amplify MIP for the period presented:
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)
Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
(2)
The aggregate grant date fair value of TSUs issued for the period from May 5, 2017 through December 31, 2017 was $2.2 million based on a grant date market price ranging from $10.00 to $13.77 per share.
(3)
The aggregate grant date fair value of TSUs issued for the year ended December 31, 2018 was $4.6 million based on a grant date market price ranging from $9.30 to $11.00 per share.
(4)
Certain Legacy Amplify departing executives forfeited 298,354 TSUs during the year ended December 31, 2018, in connection with their separation and retirement agreements.
(5)
The aggregate grant date fair value of TSUs issued for the period from January 1, 2019 through August 5, 2019 was $2.0 million based on a grant date market price ranging from $4.48 to $8.70 per share.
(6)
The merger ratio used to convert Legacy Amplify TSUs into newly issued TSUs.
(7)
This reflects the unvested TSUs converted into newly issued Company’s TSUs at August 6, 2019 at a stock price of $5.12 per share.
(8)
The aggregate grant date fair value of TSUs issued for the period August 6, 2019 through December 31, 2019 was $0.1 million based on a grant date market price of $6.14 per share.
Restricted Stock Units with Market and Service Vesting Conditions
Restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost related to the PSUs was $0.1 million at December 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.4 years.
The PSUs will vest based on the satisfaction of service and market vesting conditions with market vesting based on the Company’s achievement of certain share price targets. The PSUs are subject to service-based vesting such that 50% of the PSUs service vest on the applicable market vesting date and an additional 25% of the PSUs service vest on each of the first and second anniversaries of the applicable market vesting date.
In the event of a qualifying termination, subject to certain conditions, (i) all PSUs that have satisfied the market vesting conditions will fully service vest, upon such termination, and (ii) if the termination occurs between the second and third anniversaries of the grant date, then PSUs that have not market vested as of the termination will market vest to the extent that the share targets (in each case, reduced by $0.25) are achieved as of such termination. Subject to the foregoing, any unvested PSUs will be forfeited upon termination of employment.
A Monte Carlo simulation was used to determine the fair value of these awards at the grant date.
The assumptions used to estimate the fair value of the PSUs are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information regarding the PSUs granted under the Legacy Amplify MIP for the period presented:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)
Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
(2)
The aggregate grant date fair value of PSUs issued for the year ended December 31, 2018 was $3.2 million based on a calculated fair value price ranging from $5.88 to $9.87 per share.
(3)
The aggregate grant date fair value of PSUs issued for the period January 1, 2019 through August 5, 2019 was less than $0.1 million based on a calculated fair value price ranging from $1.64 to $6.76 per share.
(4)
The merger ratio used to convert Legacy Amplify PSUs into newly issued Company PSUs.
(5)
This reflects the unvested PSU awards converted into newly issued PSUs at August 6, 2019 based on a calculated fair value price ranging from $1.64 to $2.63 per share.
(6)
The aggregate grant date fair value of PSUs issued for the period August 6, 2019 through December 31, 2019 was less than $0.1 million based on a calculated fair value price ranging from $2.38 to $3.40 per share.
Emergence Awards
On May 4, 2017, the Legacy Amplify board of directors approved grants of restricted stock unit awards and restricted stock options (collectively the “Emergence Awards”) to certain of Legacy Amplify employees, including Legacy Amplify’s executive officers. Emergence Awards generally vest annually in three equal installments on each of the first three anniversaries of the Effective Date, subject to the grantee’s continued employment through each such vesting date. However, upon a grantee’s termination of employment by the Company without Cause, or due to death or Disability, or the grantee resigns from Service for Good Reason (as such terms are defined in the respective Emergence Award agreement), all unvested restricted stock unit awards shall fully vest upon such termination or resignation date. Moreover, (i) upon a grantee’s termination of employment by the Company without Cause, or due to death or Disability, or the grantee resigns from Service for Good Reason (as such terms are defined in the respective Emergence Award agreement), any portion of the then unvested restricted stock options that would have vested had the grantee continued his or her Service during the 12 months following such termination or resignation shall vest on such termination or resignation date and (ii) upon a grantee’s termination of employment by the Company without Cause or the grantee resigns from Service for Good Reason, in each case, following a Change of Control, all unvested restricted stock options shall fully vest as of such termination or resignation date. Notwithstanding the foregoing, the vesting of such Emergence Awards may be subject to and limited by employment-related agreements by and between the Company and grantee.
Restricted Stock Options
Restricted stock options are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense.
The fair value for restricted stock options granted during the year ended December 31, 2017 had been estimated using Black-Scholes option pricing model using the following assumptions:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information regarding the restricted stock option awards granted under the Legacy Amplify MIP for the period presented:
(1)
Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
(2)
In connection with certain grants awarded in 2018 pursuant to the Legacy Amplify MIP, all remaining unvested restricted stock options were forfeited.
Stock Option Modification
On April 27, 2018, in connection with the separation and retirement of certain Legacy Amplify executives, the board of directors of Legacy Amplify approved the acceleration of the vesting schedule for 298,354 unvested restricted stock option awards with an exercisable period of two years that otherwise would have been forfeited upon an involuntary termination.
The acceleration of the restricted stock options vesting schedule represented an improbable to probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of $0.3 million was recognized during the year ended December 31, 2018.
The modified-date grant fair value was estimated at December 31, 2018 using the Black-Scholes option pricing model using the following assumptions:
2017 Non-Employee Directors Compensation Plan
In June 2017, in connection with the Plan, Legacy Amplify implemented the Legacy Amplify Non-Employee Directors Compensation Plan to attract and retain services of experienced non-employee directors of the Company or its subsidiaries. At December 31, 2019, 104,503 shares remain available for issuance under the Legacy Amplify Non-Employee Directors Compensation Plan.
The Legacy Amplify Non-Employee Directors Compensation Plan awards are granted in the form of nonqualified stock options, restricted stock awards, restricted stock units, and other cash-based awards and stock-based awards. To the extent that an award under the Legacy Amplify Non-Employee Directors Compensation Plan is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the Legacy Amplify Non-Employee Directors Compensation Plan. Awards granted generally vest annually in three equal installments on each of the first three anniversaries of the grant date, subject to the grantee’s continued employment through each such vesting date.
The restricted stock units with a service vesting condition (“Board RSUs”) granted are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with Board RSUs was less than $0.1 million at December 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information regarding the Board RSUs granted under the Director Compensation Plan for the period presented:
(1)
Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
(2)
The aggregate grant date fair value of Board RSUs issued in 2017 was $0.2 million based on grant date market price of $13.77 per share.
(3)
The aggregate grant date fair value of Board RSUs issued in 2018 was $0.3 million based on a grant date market price of $10.45 per share.
(4)
The aggregate grant date fair value of Board RSUs issued for the period from January 1, 2019 through August 5, 2019 was $0.3 million based on a grant date market price of $6.95 per share.
(5)
The merger ratio used to convert Legacy Amplify Board RSUs into newly issued Company Board RSUs.
(6)
This reflects the unvested Board RSU awards converted into newly issued Board RSUs at August 6, 2019 in which the stock price was at $5.12 per share.
Predecessor Restricted Common Units
In December 2011, the board of directors of our Predecessor’s general partner adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, who perform services for the Predecessor. The LTIP authorized the grant of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights (“DERs”), other unit-based awards and unit awards. The LTIP initially limited the number of common units that could be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that were cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations would have been available for delivery pursuant to other awards. The LTIP was administered by the board of directors of our Predecessor’s general partner or a committee thereof.
The restricted common units awarded were subject to restrictions on transferability, customary forfeiture provisions and typically graded vesting provisions in which one-third of each award vested on the first, second, and third anniversaries of the date of grant. Award recipients had all the rights of a Predecessor with respect to the restricted common units, including the right to receive distributions thereon if and when distributions were made by the Predecessor to its unitholders. The term “restricted common unit” represented a time-vested unit. Such awards were non-vested until the required service period expired.
The restricted common units granted were accounted for as equity-classified awards. The grant-date fair value was recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures accounted for as they occur. The fair value of the restricted unit awards granted to the independent directors of our Predecessor’s general partner was also recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs were recorded as direct general and administrative expenses.
On May 1, 2017, the Company effectively cancelled the unvested restricted common unit awards under the LTIP and recorded $2.3 million in compensation expense.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information regarding restricted common unit awards for the periods presented:
(1)
Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
Predecessor Phantom Units
The following table summarizes information regarding the Predecessor’s phantom unit awards granted under the LTIP:
Phantom units issued to non-employee directors of our Predecessor in January 2016 vested on the first anniversary of the date of grant and were settled in cash for less than $0.1 million. Phantom units issued to certain employees in June 2016 were scheduled to vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient would receive, upon vesting, receive a cash payment with respect to each phantom unit equal to any cash distributions that we pay to a holder of a common unit. DERs were treated as additional compensation expense. Upon vesting, the phantom units were scheduled to be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our Predecessor’s general partner, in its discretion, was permitted to elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. Upon emergence from bankruptcy, the remaining awards were settled in cash for less than $0.1 million.
Midstates Restricted Stock Units
Midstates restricted stock units are accounted for as equity-classified awards. Restricted stock units granted to employees in 2019 under the Midstates 2016 LTIP would have vested in full on March 1, 2021, or upon the occurrence of a change in control. Upon the closing of the Merger all restricted stock units outstanding vested.
On August 5, 2019 Midstates had 585,547 restricted stock units outstanding related to employees and certain executive management and in connection with the Merger all outstanding restricted stock units vested. No restricted stock units were outstanding at December 31, 2019.
Midstates 2019 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition
On March 7, 2019, Midstates issued 193,921 restricted stock units to certain members of Midstates executive management team that contained a market vesting condition. Midstates previously accounted for these restricted stock awards as equity awards. In connection with the Merger all 193,921 restricted stock units issued were cancelled and no shares were outstanding at December 31, 2019.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Midstates Stock Options
The Midstates stock options are accounted for as equity-classified awards. Stock Option awards outstanding under the Midstates 2016 LTIP would have vested ratably over a period of three years: one-sixth vest on the six-month anniversary of the grant date, an additional one-sixth vest on the twelve-month anniversary of the grant date, an additional one-third vest on the twenty-four month anniversary of the grant date and the final one-third vest on the thirty-six month anniversary of the grant date. Stock Option awards expire 10 years from the grant date. On August 5, 2019, Midstates had 54,365 stock options outstanding and in connection with the Merger all outstanding stock options vested. No stock options were outstanding at December 31, 2019.
Midstates Non-Employee Director Restricted Stock Units Containing a Market Condition
On November 23, 2016, Midstates issued restricted stock units to non-employee directors that contained a market vesting condition. Midstates previously recognized the non-employee director restricted stock units containing a market condition as liability awards. On August 5, 2019, Midstates had 50,864 market condition awards outstanding and in connection with the Merger all restricted stock units to non-employee directors that contained a market vesting condition vested. No shares were outstanding at December 31, 2019 related to non-employee director restricted stock units containing a market condition.
Compensation Expense
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
Note 15. Leases
The Company adopted ASU 842, leases, on January 1, 2019 using the modified retrospective approach with a cumulative impact to retained earnings. The adoption of this standard has resulted in an increase in the assets and liabilities on the Company’s Condensed Consolidated Balance Sheet. The Company has completed the review and evaluation of current and potential leases which resulted primarily in our corporate office lease and some minor equipment and vehicle leases qualifying under the new guidance. Based upon this analysis, the impact of the new guidance established a liability and the corresponding asset of $5.4 million at January 1, 2019.
For the year ended December 31, 2019, our leases qualify as operating leases and we did not have any existing or new leases qualifying as financing leases. We have leases for office space and equipment in our corporate office and operating regions as well as vehicles, compressors and surface rentals related to our business operations. In addition, we have offshore Southern California pipeline right-of-way use agreements. Most of our leases, other than our corporate office lease, have an initial term and may be extended on a month-to-month basis after expiration of the initial term. Most of our leases can be terminated with 30-day prior written notice. The majority of our month-to-month leases are not included as a lease liability in our balance sheet under ASC 842 because continuation of the lease is not reasonably certain. Additionally, the Company elected the short-term practical expedient to exclude leases with a term of twelve months or less.
Our corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, we use our incremental borrowing rate based on the information available at the inception date. To determine the incremental borrowing rate, we apply a portfolio approach based on the applicable lease terms and the current economic environment. We use a reasonable market interest rate for our office equipment and vehicle leases.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the Company’s right-of-use assets and lease liabilities as of December 31, 2019.
The following table reflects the Company’s maturity analysis of the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):
The following is a schedule of the Company’s future contractual payment for operating leases prepared in accordance with accounting standards prior to the adoption of ASC 842, as of December 31, 2018 (in thousands):
The weighted average remaining lease terms and discount rate for all of our operating leases were as follow as of December 31, 2019:
During the year ended December 31, 2019, the Company recorded a $4.2 million loss on lease, which relates 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.
We have instituted internal controls going forward to monitor and evaluate new leases for appropriate accounting under the new guidance.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 16. Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Accrued Liabilities
Current accrued liabilities consisted of the following at the dates indicated (in thousands):
Cash and Cash Equivalents Reconciliation
The following table provides a reconciliation of cash and cash equivalents on the Consolidated Balance Sheet to cash, cash equivalents and restricted cash on the Statements of Consolidated Cash Flows (in thousands):
Supplemental Cash Flows
Supplemental cash flow for the periods presented (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 17. Related Party Transactions
Related Party Agreements
The Predecessor and certain of our former affiliates entered into various documents and agreements. These agreements were negotiated among affiliated parties and, consequently, were not the result of arm’s-length negotiations. Since our emergence from bankruptcy on May 4, 2017, there have been no transactions in excess of $120,000 between us and a related person in which the related person had a direct or indirect material interest.
Note 18. Commitments and Contingencies
Litigation and Environmental
As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters.
Other than the Chapter 11 proceedings discussed herein, based on facts currently available, 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; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.
Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable.
At December 31, 2019 and 2018, we had no environmental reserves recorded.
Third-Party Midstream Transaction
In October 2017, Legacy Amplify recognized an approximately $17.0 million gain in connection with the sale of a third-party midstream entity with whom our natural gas gathering and processing agreements entitled us to a percentage of the proceeds in the event of a sale.
Application for Final Decree
On April 30, 2018, the Legacy Amplify Debtors filed with the Bankruptcy Court a motion for a final decree and entry of an order closing the Chapter 11 cases with respect to each of the Legacy Amplify Debtors other than (i) San Pedro Bay Pipeline Company, Ch. 11 Case No. 17-30249, (ii) Rise Energy Beta, LLC, Ch. 11 Case No. 17-30250, and (iii) Beta Operating Company, LLC, Ch. 11 Case No. 17-30253, (collectively, the “Closing Debtors”). On May 30, 2018, the Bankruptcy Court entered the final decree closing the Chapter 11 cases of the Closing Debtors.
Sinking Fund Trust Agreement
Beta Operating Company, LLC (“Beta”) assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of our properties in federal waters offshore Southern California, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay Pipeline that lies within state waters and the surface facilities. Under the terms of the agreement, the operator of the properties is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2019, the account balance included in restricted investments was approximately $4.6 million.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Bond for Decommissioning Liabilities Trust Agreement
Beta has an obligation with the BOEM in connection with the 2009 acquisition of the Beta properties. On October 5, 2018, the Company received approximately $61.5 million from the trust account (the “Beta Decommissioning Trust Account”). On November 20, 2018, the Company received an additional $1.0 million from the Beta Decommissioning Trust Account that had been withheld from the initial payment on October 5, 2018. The cash released to the Company’s balance sheet was made pursuant to an order of the Bankruptcy Court dated February 9, 2018, which allowed for the release of Beta cash subject to certain conditions that have since been satisfied.
The Company had previously supported this obligation with $71.3 million of A-rated surety bonds and $90.2 million in cash, but $90.0 million of cash was released to the Company on June 24, 2019. Following the release, Beta’s decommissioning obligations remain fully supported by $161.3 million in A-rated surety bonds and $0.3 million in cash.
Operating Leases
We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment, compressors and incur surface rentals related to our business 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, we recognized $7.5 million, $8.6 million, $6.3 million and $3.1 million of rent expense, respectively.
See Note 15 for the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year.
Purchase Commitments
At December 31, 2019, we had a CO2 purchase commitment with a third party associated with our Wyoming Bairoil properties. The price we will pay for CO2 generally varies depending on the amount of CO2 delivered and the price of oil. The table below outlines our purchase commitments under these contracts based on pricing at December 31, 2019 (in thousands):
Minimum Volume Commitment
At December 31, 2019, we had a long-term minimum volume commitment with a third party associated with a certain portion of our properties located in Oklahoma and East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands):
The Company is party to a gas purchase, gathering and processing contract in Oklahoma, which includes certain minimum NGL commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLS, it would be required to reimburse the counterparty an amount equal to sum of the monthly shortfall, if any, multiplied by a fee. Beginning in June 2019, the Company is not meeting the minimum volume required under these contractual provisions. The commitment fee/expense for June through December 2019 was $0.7 million and the average estimated fee for 2020 is expected to be $0.1 million per month.
Note 19. Income Tax
Amplify Energy is a corporation and as a result, is subject to U.S. federal, state and local income taxes.
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% of taxable income.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of income tax benefit (expense) are as follows:
The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% in 2019, 21% in 2018 and 35% in 2017 as follows:
(1)
MEMP, a publicly traded partnership with qualifying income, was a pass-through entity for federal income tax purposes.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands):
As of December 31, 2019, the Company had approximately $618.0 million of federal net operating loss carryovers of which $590.6 million have no expiration date and the remaining will expire in year 2037. As of December 31, 2019, the Company had approximately $238.5 million of state net operating loss carryovers of which $203.9 million have no expiration period and the remaining will expire in varying amounts beginning in 2037.
In assessing deferred tax assets, the Company considers whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, the Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. A valuation allowance is established against deferred tax assets for which management believes realization is considered to be more likely than not that all of the deferred tax assets will not be realized. As of December 31, 2019, a valuation allowance of $189.9 million had been recorded which is an increase to the valuation allowance of $166.0 million from the prior year.
Uncertain Income Tax Position. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. We had no unrecognized tax benefits as of December 31, 2019.
Tax Audits and Settlements. Currently, the Internal Revenue Service (IRS) is auditing our 2017 tax year; however, there have been no proposed adjustments or resolutions communicated to the Company. Our income tax years 2018 and 2019 remain open and subject to examination by the IRS. For state and local jurisdictions, our 2017 through 2019 tax years remain open and subject to examination where we conduct operations. In certain jurisdictions we operate through more than one legal entity, each of which may have different open years subject to examination.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 20. Quarterly Financial Information (Unaudited)
The following tables present selected quarterly financial data for the periods indicated. Earnings per share/unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per share/unit may not necessarily equal the total for the year.
See Notes 4 and 13 for additional information regarding earnings per share/unit.
Note 21. Supplemental Oil and Gas Information (Unaudited)
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
Oil and Natural Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
We engaged Cawley, Gillespie and Associates (“CG&A”) to prepare our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2019. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:
(1)
The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.
(2)
The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
The following tables set forth estimates of the net reserves for the periods indicated:
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Noteworthy amounts included in the categories of proved reserve changes in the above tables include:
•
The 22.8 MMBoe increase in reserves for the year ended December 31, 2019 is primarily due to the Merger in which we acquired 69.7 MMBoe partially offset by downward pricing revision of a 25.9 MMBoe and a downward revision of 12.1 MMBoe due to updated well performance data and future anticipated maintenance cost increases.
•
The 24.7 MMBoe reduction in reserves for the year ended December 31, 2018 is primarily due to a 4.6 MMBoe upward pricing revision and a 10.6 MMBoe downward revision due to updated well performance data and future anticipated development and maintenance cost increases. We divested 11.0 MMBoe during the year ended December 31, 2018. We added 1.9 MMBoe during the year ended December 31, 2018 due to extensions and discoveries.
•
The 16.5 MMBoe reduction in reserves for the period from May 5, 2017 through December 31, 2017 is primarily due to a 2.2 MMBoe upward pricing revision and a 12.8 MMBoe downward revision due to updated well performance data and future anticipated development and maintenance cost increases. We added 1.2 MMBoe during the period from May 5, 2017 through December 31, 2017 due to extensions and discoveries.
•
The 28.7 MMBoe increase in reserves for the January 1, 2017 through May 4, 2017 is primarily due to a 34.1 MMBoe upward pricing revision and a 1.5 MMBoe downward revision due to updated well performance data. Proved undeveloped reserves increased primarily due to upward pricing during the period from January 1, 2017 through May 4, 2017.
See Note 6 for additional information on acquisitions and divestitures.
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
The standardized measure of discounted future net cash flows is as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2019:
AMPLIFY ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note. 22 Subsequent Events
Departure of Certain Officers
On January 30, 2020, Richard P. Smiley notified the Company of his intent to resign from his current position as Senior Vice President, Operations. Mr. Smiley intends to remain in his role at the Company to assist with an orderly transition of his responsibilities. Mr. Smiley did not resign from the position of Senior Vice President, Operations due to any disagreement with the Company or any matter relating to the Company’s operations, policies or practices.