EDGAR 10-K Filing

Company CIK: 10254
Filing Year: 2021
Filename: 10254_10-K_2021_0000010254-21-000045.json

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ITEM 1. BUSINESS
Item 1. Business
Overview
Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with our consolidated subsidiaries, the “Company,” “our,” “we,” “us,” or similar terms), is a growth-oriented independent oil and gas company engaged in the acquisition and development of oil and gas reserves through activities that include the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions and mergers. Our operations are all in the upstream segment of the oil and natural gas industry and all our properties are onshore in the United States. At present, our assets are located in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas.
Our primary focus is concentrated in the Midland Basin of west Texas, a high oil and liquids rich resource basin which provides us with multiple horizontal targets with proven production results, long-lived reserves and historically high drilling success rates.
IRM Acquisition
On January 7, 2021, Earthstone, Earthstone Energy Holdings, LLC, a subsidiary of the Company (“EEH” and collectively with Earthstone, the “Buyer”), Independence Resources Holdings, LLC (“Independence”), and Independence Resources Manager, LLC (“Independence Manager” and collectively with Independence, the “Seller”) consummated the transactions contemplated in the Purchase and Sale Agreement dated December 17, 2020 (the “Purchase Agreement”) that was previously reported on Form 8-K. The Seller was unaffiliated with the Company. At the closing of the Purchase Agreement, among other things, EEH acquired (the “IRM Acquisition”) all of the issued and outstanding limited liability company interests in certain wholly owned subsidiaries of Independence and Independence Manager (collectively, the “Acquired Entities”) for aggregate consideration consisting of the following: (i) an aggregate amount of cash from EEH equal to approximately $131.2 million (the “Cash Consideration”) and (ii) 12,719,594 shares of the Company’s Class A common stock, $0.001 par value per share (“Class A Common Stock”), issued to Independence (such shares, the “Acquisition Shares,” and such issuance, the “Stock Issuance”). As a result of the Stock Issuance, Earthstone is no longer considered a controlled company within the meaning of the NYSE rules.
Amendment to Credit Agreement - In preparation for the IRM Acquisition, on December 17, 2020, Earthstone, EEH, as Borrower, Wells Fargo Bank, National Association (“Wells Fargo”), as Administrative Agent, the guarantors party thereto, and the lenders party thereto (the “Lenders”) entered into an amendment (the “Amendment”) to the credit agreement dated November 21, 2019, by and among EEH, as Borrower, Earthstone, as Parent, Wells Fargo, as Administrative Agent and Issuing Bank, BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, and the Lenders party thereto (together with all amendments or other modifications, the “Credit Agreement”). The Amendment was effective upon the closing of the IRM Acquisition on January 7, 2021. Among other things, the Amendment (i) joined certain financial institutions as additional lenders, increased the borrowing base from $240.0 million to $360.0 million, (ii) increased the interest rate on outstanding borrowings; and (iii) adjusted some of the financial covenants.
Registration Rights Agreement - On January 7, 2021, in connection with the closing of the Purchase Agreement, Earthstone and Independence entered into a registration rights agreement (the “Registration Rights Agreement”) relating to the IRM Acquisition Shares and the shares of Class A Common Stock that Independence acquired from EnCap Investments L.P. and its affiliates (“EnCap”) on January 7, 2021 (collectively, the “Registrable Securities”). The Registration Rights Agreement provides that Earthstone will file a registration statement to permit the public resale of the Registrable Securities. Earthstone shall cause the registration statement to be continuously effective from its effective date until all of the Registrable Securities have been disposed of in the manner set forth in the registration statement or under Rule 144 of the Securities Act, until the distribution of the Class A Common Stock does not require registration under the Securities Act, or until there are no longer any Registrable Securities outstanding.
Voting Agreement - On January 7, 2021, in connection with the closing of the Purchase Agreement, Warburg Pincus Private Equity (E&P) XI - A, L.P. (“WPXI-A”), Warburg Pincus XI (E&P) Partners - A, L.P. (“WPPXI”), WP IRH Holdings, L.P. (“WPIRH”), Warburg Pincus XI (E&P) Partners - B IRH, LLC (“WPXI-B”), Warburg Pincus Energy (E&P)-A, LP (“WPE-A”), Warburg Pincus Energy (E&P) Partners-A, LP (“WPEP-A”), Warburg Pincus Energy (E&P) Partners-B IRH, LLC (“WPEP-B”), WP Energy Partners IRH Holdings, L.P. (“WPEPIRH”), and WP Energy IRH Holdings, L.P. (“WPEIRH” and collectively with WPXI-A, WPPXI, WPIRH, WPXI-B, WPE-A, WPEP-A, WPEP-B and WPEPIRH, the “Warburg Parties”), EnCap and Earthstone entered into a voting agreement (the “Voting Agreement”) containing provisions by which the Warburg Parties will have the right to appoint one director to the Board of Directors (the “Board”) of Earthstone. The Warburg Parties’ right to appoint one director will terminate when the Warburg Parties, in the aggregate, no longer own: (i) 8% of the outstanding Class A Common Stock; or (ii) 10% or more of the outstanding Class A Common Stock as a result of a sale by the
Warburg Parties. The Warburg Parties nominated David S. Habachy and the Board appointed Mr. Habachy as a Class II director who will hold office until Earthstone’s annual meeting of stockholders in 2023.
Lock-Up Agreement - In connection with the closing of the Purchase Agreement, on January 7, 2021, Earthstone entered into a Lock-up Agreement (the “Lock-up Agreement”) with the Warburg Parties, pursuant to which the Warburg Parties are restricted for a period of 120 days (the “Lock-up Period”) after January 7, 2021 from offering, pledging, selling, contracting to sell, selling any option or contract to purchase, purchasing any option or contract to sell, granting any option, right or warrant to purchase, lending or otherwise transferring or disposing of any shares of Class A Common Stock or any other class of Earthstone’s capital stock (collectively, “Capital Stock”), or enter into any swap or other agreement, arrangement or transaction that transfers to another any of the economic consequence of ownership of any Capital Stock or any securities convertible into or exercisable or exchangeable for any Capital Stock. The foregoing restrictions will not apply to certain other transfers customarily excepted and any shares of Class A Common Stock acquired by the Warburg Parties in the open market after January 7, 2021.
Our Properties
With 407 potential gross horizontal drilling locations (262 operated / 145 non-operated) in the Midland Basin as of December 31, 2020, we are focused on developmental drilling and completion operations in the area. As a result of the IRM Acquisition, we added 43,400 additional net acres with 750 gross / 738.5 net operated producing wells and 2 gross / 1.0 net non-operated wells. The acquisition includes 4,900 net core acres located in Midland and Ector counties with 70 additional gross drilling locations. The remaining acreage is located primarily in Irion and Sterling Counties.
We continue to pursue acreage trades or bolt-on acreage acquisitions in the Midland Basin with the intent of increasing our operated acreage and drilling inventory, drilling and completing longer laterals and realizing greater operating efficiencies.
As of December 31, 2020, we had approximately 27,900 net acres in the core of the Midland Basin that are highly contiguous on a project-by-project basis which allow us to drill multi-well pads. Of this acreage, 78% is operated and 22% is non-operated. We hold an approximate 93% working interest in our operated acreage and an approximate 40% working interest in our non-operated acreage. Our operated acreage in the Midland Basin is primarily located in Reagan, Upton and Midland counties which includes 88 gross / 77.3 net producing wells. Our non-operated acreage in the Midland Basin is located primarily in Howard, Glasscock, Martin, Midland and Reagan counties which includes 140 gross / 48.4 net producing wells.
As of December 31, 2020, we had approximately 12,500 net leasehold acres in the Eagle Ford Trend, primarily in the crude oil window in Fayette, Gonzales and Karnes counties which include 115 gross / 51.4 net operated producing wells and 6 gross / 1.1 net non-operated wells.
As operator, we manage and are able to directly influence development and production of our operated properties. Independent contractors engaged by us provide all the equipment and personnel associated with drilling and completion activities. We employ petroleum engineers, geologists and land professionals who work on improving operating cost, production rates and reserves. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price and cost fluctuations. Our status as an operator has allowed us to pursue the development of undeveloped acreage, further develop existing properties and generate new projects.
As is common in our industry, we selectively participate in drilling and developmental activities in non-operated properties. Decisions to participate in non-operated properties are dependent upon the technical and economic nature of the projects and the operating expertise and financial standing of the operators.
As of December 31, 2020, our estimated proved oil and natural gas reserves were approximately 78,875 MBOE based on the reserve report prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent petroleum engineers. Based on this report, at December 31, 2020, our estimated proved reserve quantities were approximately 51% oil, 24% natural gas and 26% NGLs with 49% of those reserves classified as proved developed.
As a result of the IRM Acquisition, we added an estimated 16,300 MBoe of proved developed producing reserves which were approximately 60% oil, 18% natural gas and 23% NGLs.
Our Business Strategy
We believe that the current industry environment will result in more consolidations; however, execution may be hampered by the high debt levels of many producers. We continue to pursue value-accretive and scale-enhancing consolidation opportunities, as we believe we are in a position to operate effectively despite the volatility in commodity prices experienced over the past several years. We are focusing our attention on acquisition and corporate merger opportunities that would increase the scale of our operations, without materially altering our debt metrics in relation to our cash flows and capital. In addition, we believe the current industry environment presents unique opportunities to acquire distressed assets or corporations that will be financially distressed in the near future which should provide us the potential for further consolidation based on our financial strength. At the same time, we will seek to block up acreage in the Midland Basin that would allow for longer horizontal laterals and should
therefore provide for higher economic returns. In summary, we believe we are well qualified to be a consolidator which would increase the scale of our operations and add value to our shareholders.
Our current business strategy is to focus on the economic development of our existing acreage, increase our acreage and horizontal well locations in the Midland Basin and increase stockholder value through the following:
•developing our acreage and profitably growing our production while seeking to achieve Free Cash Flow (defined in “Non-GAAP Measures” below);
•operating our properties efficiently and continuing to improve our operating margins;
•deploying capital efficiently by drilling multi-well pads, reducing drilling times and increasing completions per day;
•operating our assets in a safe and environmentally sensitive manner;
•continuing to hedge commodity prices as opportunities arise;
•pursuing value-accretive acquisition and corporate merger opportunities, which could increase the scale of our operations;
•maximizing operating margins and corporate level cash flows by minimizing operating and overhead costs;
•expanding our acreage positions and drilling inventory in our primary areas of interest through acquisitions and farm-in opportunities, with an emphasis on operated positions;
•blocking up acreage to allow for longer horizontal lateral drilling locations which provide higher economic returns; and
•maintaining a strong balance sheet and financial flexibility.
Our Strengths
We believe that the following strengths are beneficial in achieving our business goals:
•extensive horizontal development potential in one of the most oil rich basins of the United States;
•experienced management team with substantial technical and operational expertise;
•ability to attract technical personnel with experience in our core area of operations;
•history of successful acquisition and merger transactions;
•operating control over the majority of our production and development activities;
•financial discipline;
•conservative balance sheet;
•commitment to cost efficient operations; and
•a management team that is well known and respected throughout the industry.
2020 Highlights
The following are highlights of our 2020 activities compared to activity in 2019:
•Signed Purchase and Sale Agreement on the IRM Acquisition on December 17, 2020 which was closed on January 7, 2021 (see below)
•Full year 2020 average daily sales volumes of 15,276 Boepd exceeded our production goals and increased 14%
•Reduced outstanding long-term debt in 2020 by 32%, from $170.0 million to $115.0 million
•Realized $56.0 million from our hedge positions thereby mitigating commodity price volatility
•Strong balance sheet and liquidity position with $125.0 million of undrawn capacity on a $240.0 million senior revolving credit facility and a cash balance of $1.5 million as of December 31, 2020
•Advanced our business strategy despite the impact of COVID-19 on commodity prices and the industry.
Commodity Price Recovery
As oil prices have recovered recently from their 2020 lows, we are preparing to resume drilling operations with the deployment of a rig late in the first quarter of 2021 and we expect to spend $90-$100 million in total capital expenditures during 2021 based on our current 2021 capital spending plan.
Officer Appointments
Effective April 1, 2020, our former Chairman and Chief Executive Officer, Mr. Frank A. Lodzinski, was appointed Executive Chairman and our President, Mr. Robert J. Anderson, was appointed President and Chief Executive Officer.
COVID-19
Despite the recent recoveries in commodity prices, the COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of financial and commodity markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been significant volatility in demand for and prices of oil and natural gas. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including how the pandemic and measures taken in response to its impact on demand for oil and natural gas, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. There is uncertainty around the extent and duration of disruption, including any resurgence, and we expect that the longer the duration of any such disruption, the greater the adverse impact may be on our business. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the pandemic, its severity, the actions to contain the virus or treat its impact, its impact on the U.S. and world economies, the U.S. capital markets and market conditions, and how quickly and to what extent normal economic and operating conditions can resume.
Operational Status
As a producer of oil, natural gas and NGLs, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. We have continued to operate as permitted under these regulations while taking mitigation efforts and steps to protect the health and safety of our employees. The safety of our employees is paramount, and we have emphasized the respective guidelines to support our mitigation efforts. Our field personnel are performing their job responsibilities and practicing mitigation guidelines with no issues to date. Our non-field personnel had been working remotely, using information technology in which we previously invested. More recently, the majority of our non-field personal have been working at our corporate offices while adhering to local county and CDC guidelines. Upon returning to work at our corporate offices, we implemented protocols that consist of required mask wearing zones, use of installed sanitization equipment in various locations and practice social distancing in gathering areas such as conference rooms. We have managed and conducted both field and non-field functions effectively thus far, including our day-to-day operations, our accounting and financial reporting systems and our internal control over financial reporting. We will continue to focus on the health and safety of our employees in conformity with the applicable jurisdictional mitigation guidelines.
Commodity Market Challenges
The significant decline in commodity prices resulting from the COVID-19 pandemic negatively impacted producers of oil, natural gas and NGLs in the U.S. and elsewhere. The COVID-19 pandemic resulted in global consumer demand contraction and the ensuing supply/demand imbalance has had a disruptive impact on oil and gas exploration and production. In April 2020, WTI crude oil prices averaged $16.55/Bbl and briefly fell below $0/Bbl, closing at -$36.98/Bbl on April 20, 2020. In response, management began to voluntarily shut-in as much production as was feasible in an effort to preserve reserves to sell in the future. As prices returned to economic levels, management returned those wells to production as quickly as possible, beginning in late May and early June. Management estimates that total net production was curtailed by approximately 60% in May, with minimal volumes curtailed in April and June. Since June 2020, we have returned to operating at full production capacity as oil prices have continued to recover. Additionally, based on the current recovered commodity price levels, we plan to commence a drilling program late in the first quarter of 2021.
Operational/Financial Challenges
It is difficult to model and predict how our operations and financial status may change as a result of COVID-19. In our industry, any forecast, plans and changes to operations and financial status are a function of commodity prices. If oil prices decline due to a resurgence of COVID-19, we believe we can continue to operate and produce our properties at a minimum in a cash flow neutral position for the next 12 months. We will have to manage the possibility of well shut-ins, both voluntary and involuntary,
to preserve our assets and cash flows. A significant driver in the future may be the financial institutions’ view on commodity prices with respect to borrowing base redeterminations. If a resurgence of COVID-19 triggers additional volatility in our business or global economies, our borrowing base, currently set at $360 million, could be reduced. Significant reductions in the borrowing base under our Credit Agreement could create a borrowing base deficiency depending on or loans then outstanding which may lead to a default. We believe global, as well as national, mitigation efforts currently being implemented to fight COVID-19 have had, and may continue to have, a material impact on commodity prices and may continue to present significant challenges to our industry.
The effects of COVID-19, including a substantial decrease in economic activity, have contributed to significant credit, debt and equity market volatility. Similar to other producers in our business, we experienced volatility in the price of our Class A common stock.
Impairments
We recorded impairments in the first quarter of 2020 resulting, in part, from the effects of COVID-19 (in thousands):
Eagle Ford Trend Midland Basin Corporate Total
Proved properties $ 25,252 $ - $ - $ 25,252
Unproved properties 11,311 - - 11,311
Acreage expirations (1) 394 5,794 - 6,188
Goodwill - - 17,620 17,620
$ 36,957 $ 5,794 $ 17,620 $ 60,371
(1)Impairments in unproved properties resulting from acreage deemed expired (not planned to be renewed)
Government Assistance
Although management explored all assistance available under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), the Company was not eligible for any of the programs therein with the exception of the deferral of employment tax deposits and payments which management has currently not elected to pursue.
Employee Reduction Measures
In June 2020, management completed a workforce reduction effort that reduced the number of full-time employees from 68 to 60 by month end, resulting in over a 10% decrease in aggregate salaries and wages. Severance related costs associated with these reduction measures resulted in operating expenses of $0.4 million in June 2020. At this time, management has no future plans for further workforce reductions; however, if adverse industry conditions occur, further employee reduction measures may be necessary.
Organizational Structure
Earthstone is the sole managing member of EEH, with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA, Inc. (“Lynden US”) and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH’s members other than Earthstone and Lynden US. Additionally, on January 7, 2021, upon closing of the IRM Acquisition, IRM became a wholly owned subsidiary of EEH.
Operational Risks
Oil and natural gas exploitation, development and production involve a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will acquire, discover or produce additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce our available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.
As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by
insurance could have a material effect on our operating results, financial position and cash flows. For further discussion of these risks see Item 1A. Risk Factors of this report.
Marketing and Customers
We market the majority of the production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to purchasers at market prices.
We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2020, three purchasers accounted for 32%, 15% and 12%, respectively, of our revenue during the period. For the year ended December 31, 2019, three purchasers accounted for 30%, 14% and 12%, respectively, of our revenue during the period. No other customer accounted for more than 10% of our revenue during these periods. If a major customer stopped purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, we believe that the loss of any one or all of our major purchasers would not have a materially adverse effect on our financial condition or results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Transportation
During the planning stage of our prospective and productive units and acreage, we consider required flow-lines, gathering and delivery infrastructure. Our oil is transported from the wellhead to our tank batteries or delivery points through our flow-lines or gathering systems. Purchasers of our oil take delivery at (i) our tank batteries and transport the oil by truck, or (ii) at a pipeline delivery point. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point through our gathering systems. We have implemented a Leak Detection and Repair program, or LDAR, to locate and repair leaking components including valves, pumps and connectors in order to minimize the emission of fugitive volatile organic compounds and hazardous air pollutants. In addition, we install vapor recovery units in our newer tank batteries which also reduces emissions.
We are party to a buy/sell arrangement for a certain portion of our oil production that effects a change in location with required repurchase of oil at a delivery point. This activity is recorded on a net basis and the residual transportation fee is included in Lease operating expenses in the Consolidated Statements of Operations. Arrangements such as this not only reduce our transportation costs by eliminating truck transportation but also provide additional flexibility in delivery points for our product. The decrease in transportation by truck also translates into reduced truck emissions.
Our produced salt water is generally moved by pipeline connected to our operated salt water disposal wells or by pipeline to commercial disposal facilities.
Commodity Hedging
Consistent with our disciplined approach to financial management, we have an active commodity hedging program through which we seek to hedge a meaningful portion of our expected oil and gas production, reducing our exposure to downside commodity prices and enabling us to protect cash flows and maintain liquidity to fund our capital program.
Competition
The domestic oil and natural gas industry is intensely competitive in the acquisition of acreage, production and oil and gas reserves and in producing, transporting and marketing activities. Our competitors include national oil companies, major oil and natural gas companies, independent oil and natural gas companies, drilling partnership programs, individual producers, natural gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. Many of our competitors are large, well-established companies. They may be able to pay more for seismic information and lease rights on oil and natural gas properties and to define, evaluate, bid for and purchase a greater number of properties, than our financial or human resources permit. Our ability to acquire additional properties in the future, and our ability to fund the acquisition of such properties, will be dependent upon our ability to evaluate and select suitable properties and to consummate related transactions in a highly competitive environment.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Segment Information and Geographic Area
Operating segments are defined under accounting principles generally accepted in the United States (“GAAP”) as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.
Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas acquisition, exploration, development and production. All of our operations are currently conducted in Texas.
Seasonality of Business
Weather conditions often affect the demand for, and prices of, natural gas and can also delay oil and natural gas drilling, completion and production activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
Markets for Sale of Production
Our ability to market oil and natural gas found and produced, depends on numerous factors beyond our control, the effect of which cannot be accurately predicted or anticipated. Some of these factors include, without limitation, the availability of other domestic and foreign production, the marketing of competitive fuels, the proximity and capacity of pipelines, fluctuations in supply and demand, the availability of a ready market, the effect of United States federal and state regulation of production, refining, transportation and sales and general national and worldwide economic conditions. Additionally, we may experience delays in marketing natural gas production and fluctuations in natural gas prices and we may experience short-term delays in marketing oil due to trucking and refining constraints. There is no assurance that we will be able to market any oil or natural gas produced, or, if such oil or natural gas is marketed, that favorable prices can be obtained.
The United States natural gas market has undergone several significant changes over the past few decades. The majority of federal price ceilings were removed in 1985 and the remainder were lifted by the Natural Gas Wellhead Decontrol Act of 1989. Thus, currently, the United States natural gas market is operating in a free market environment in which the price of gas is determined by market forces rather than by regulations. At the same time, the domestic natural gas industry has also seen a dramatic change in the manner in which gas is bought, sold and transported. In most cases, natural gas is no longer sold to a pipeline company. Instead, the pipeline company now primarily serves the role of transporter and gas producers are free to sell their product to marketers, local distribution companies, end users or a combination thereof.
In recent years, oil, natural gas and NGLs prices have been under considerable pressure due to oversupply and other market conditions, including constrained pipeline capacity. Specifically, increased domestic and foreign production and increased efficiencies in horizontal drilling and completion, combined with increased development of shale fields in North America, have dramatically increased global oil and natural gas production, which has led to significantly lower market prices for these commodities. In view of the many uncertainties affecting the supply and demand for oil, natural gas and NGLs, we are unable to accurately predict future oil, natural gas and NGLs prices or the overall effect, if any, that the decline in demand for and the oversupply of such products will have on our financial condition or results of operations.
Title to Properties
We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of our oil and natural gas properties. Our oil and natural gas properties are typically subject, in one degree or another, to one or more of the following:
•royalties and other burdens and obligations, express or implied, under oil and natural gas leases;
•overriding royalties and other burdens created by us or our predecessors in title;
•a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, participation agreements, production sales contracts and other agreements that may affect the properties or their titles;
•back-ins and reversionary interests existing under various agreements and leasehold assignments;
•liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;
•pooling, unitization and other agreements, declarations and orders; and
•easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the quantity and value of our reserves. We believe that the burdens and obligations affecting our oil and natural gas properties are common in our industry with respect to the types of properties we own.
Operational Regulations
All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory and regulatory provisions affecting drilling, completion, and production activities, including, but not limited to, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, while some states allow the forced pooling or integration of land and leases to facilitate development, other states including Texas, where we operate, rely primarily or exclusively on voluntary pooling of land and leases. Accordingly, it may be difficult for us to form spacing units and therefore difficult to develop a project if we own or control less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, local authorities have imposed moratoria or other restrictions on exploration, development and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration, development and production to proceed.
The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
Regulation of Transportation of Natural Gas
The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of Sales of Oil, Natural Gas and Natural Gas Liquids
The prices at which we sell oil, natural gas and natural gas liquids are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate transportation of oil, natural gas liquids, and other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate, and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action that FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
Environmental Regulations
Our operations are also subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the United States Environmental Protection Agency (the “EPA”) issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Among other things, environmental regulatory programs typically govern the permitting, construction and operation of a well or production related facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.
Beyond existing requirements, new programs and changes in existing programs, may affect our business including oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.
Hazardous Substances and Wastes
The federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct on certain categories of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA, these potentially responsible persons may be subject to strict, joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are not presently aware of any liabilities for which we may be held responsible that would materially or adversely affect us.
The Resource Conservation and Recovery Act of 1976 (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and solid (non-hazardous) wastes. With the approval of the EPA, the individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil and natural gas are currently regulated under RCRA’s solid (non-hazardous) waste provisions. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our, as well as the oil and natural gas E&P industry’s, costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on our business.
From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate such materials or wastes.
Water Discharges
The federal Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) rule defining the scope of federal jurisdiction over Waters of the United States (the “WOTUS rule”) became effective. Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule. For example, on January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows the definition of “waters of the United States” relative to the prior 2015 rulemaking. However, both this and prior rulemakings regarding the definition of WOTUS are currently subject to litigation, and it is possible that the Biden Administration could propose a broader interpretation of the Clean Water Act’s applicability. As a result of these developments, the scope of jurisdiction under the Clean Water Act is uncertain at this time.
The process for obtaining permits has the potential to delay our operations. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990 (“OPA”), impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program, and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
Hydraulic Fracturing
Our completion operations are subject to regulation, which may increase in the short- or long-term. In particular, the well completion technique known as hydraulic fracturing which is used to stimulate production of oil and natural gas has come under increased scrutiny by the environmental community, and many local, state and federal regulators. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations in order to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.
The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process.
Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the fracturing process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells.
In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. If new or more stringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
From time to time, legislation has been introduced, but not enacted, in the U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. On January 28, 2020, Senate Bill 3247 was introduced and if enacted as proposed, would ban hydraulic fracturing nationwide by 2025.
Air Emissions
The federal Clean Air Act (“CAA”) and comparable state laws restrict emissions of various air pollutants through permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas production. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants.
In 2012 and 2016, the EPA issued New Source Performance Standards to regulate emissions of sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and methane from various oil and natural gas exploration, production, processing and transportation facilities. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the Trump Administration directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rule making to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified, and existing oil and gas facilities. Given the long-term trend toward increasing regulation, future federal Greenhouse Gas (“GHG”) regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.
In October 2015, the EPA announced that it was lowering the primary National Ambient Air Quality Standards (“NAAQS”) for ozone from 75 parts per billion to 70 parts per billion. Since that time, the EPA has issued area designations with respect to ground-level ozone. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion rather than lower them further. However, as discussed above, that action could be subject to reversal following the Biden Administration’s January 2021 executive order. Reclassification of areas of state implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.
While the State of Texas has not formally conducted a recent rulemaking related to air emissions, scrutiny of oil and natural gas operations and the rules affecting them have increased in recent years. For example, the EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and natural gas production facilities and transmission infrastructure. In addition, the Texas Railroad Commission has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future.
Climate Change
In response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish construction and operating permit reviews for GHG emissions certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation (the “DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020. President Biden pledged the renewed participation of the United States on his first day in office. Although it is not possible at this time to predict how legislation or new regulations that may be adopted in the Paris Agreement to address GHG emissions would impact our business, any such future laws and 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.
Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their
investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas. Additionally, political, litigation and financial risks may result in us restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Threatened and endangered species, migratory birds and natural resources
Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the Clean Water Act. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. As a result of a 2011 settlement agreement, the FWS was required to determine whether to identify more than 250 species as endangered or threatened under the FSA by no later than completion of the agency’s 2017 fiscal year. The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result. Similar protections are offered to migratory birds under the MBTA. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds, we believe that we are in substantial compliance with the ESA and the MBTA, and we are not aware of any proposed ESA listings that will materially affect our operations. The federal government in the past has issued indictments under the MBTA to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. However, in January 2020, the Department of Interior proposed new regulations clarifying that only the intentional taking of protected migratory birds is subject to prosecution under the MTBA. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce our oil and natural gas reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
Hazard communications and community right to know
We are subject to federal and state hazard communication and community right to know statutes and regulations. These regulations, including, but not limited to, the federal Emergency Planning & Community Right-to-Know Act, govern record keeping and reporting of the use and release of hazardous substances and may require that information be provided to state and local government authorities, as well as the public.
Occupational Safety and Health Act
We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In 2016, there were substantial revisions to the regulations under OSHA that may have an impact to our operations. These changes include among other items; record keeping and reporting, revised crystalline silica standard (which requires the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021), naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.
State Regulation
Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas and natural gas liquids production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure our stockholders that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration, development and production activities. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.
Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2020, nor do we anticipate that such expenditures will be material in 2021.
Employees
As of December 31, 2020, we had 61 full-time employees, of which 10 are management, 17 are technical personnel, 15 are administrative personnel and 19 are field operations employees. Our employees are not covered under a collective bargaining agreement nor are any employees represented by a union. We consider all relations with our employees to be satisfactory.
Subsequent to the completion of the IRM Acquisition, we added 18 full-time employees, of which two are administrative personnel and 16 are field operations employees all of whom were former employees of IRM.
Office Leases
As of December 31, 2020, we leased office space as set forth in the following table:
Location
Approximate Size Lease Expiration Date Intended Use
The Woodlands, Texas 19,600 sq. ft. March 31, 2025 Office
Midland, Texas 9,200 sq. ft. June 30, 2022 Office
During 2020, aggregate rental payments for our office facilities totaled approximately $0.8 million.
On January 7, 2021, upon closing of the IRM Acquisition, EEH became party to an office lease with an effective termination date of May 31, 2021, for which the remaining obligation is approximately $0.26 million.
Information about our Executive Officers
The following table sets forth, as of March 1, 2021, certain information regarding the executive officers of Earthstone:
Name Age Position
Frank A. Lodzinski 71 Executive Chairman of the Board
Robert J. Anderson 59 President and Chief Executive Officer
Tony Oviedo 67 Executive Vice President, Accounting and Administration
Mark Lumpkin, Jr. 47 Executive Vice President and Chief Financial Officer
Steven C. Collins 56 Executive Vice President, Completions and Operations
Timothy D. Merrifield 65 Executive Vice President, Geological and Geophysical
The following biographies describe the business experience of our executive officers:
Frank A. Lodzinski has served as our Chairman since December 2014 and as Executive Chairman since April 1, 2020. He served as our Chief Executive Officer from December 2014 through March 2020. He also served as our President from December 2014 through April 2018. Previously, he served as President and Chief Executive Officer of Oak Valley Resources, LLC (“Oak Valley”) from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to his service with Oak Valley, Mr. Lodzinski was Chairman, President and Chief Executive Officer of GeoResources, Inc. from April 2007 until its merger with Halcón Resources Corporation (“Halcón”) in August 2012 and from September 2012 until December 2012 he conducted pre-formation activities for Oak Valley. He has over 47 years of oil and gas industry experience. In 1984, he formed Energy Resource Associates, Inc., which acquired management and controlling interests in oil and gas limited partnerships, joint ventures and producing properties. Certain partnerships were exchanged for common shares of Hampton Resources Corporation in 1992, which Mr. Lodzinski joined as a director and President. Hampton was sold in 1995 to Bellwether Exploration Company. In 1996, he formed Cliffwood Oil & Gas Corp. and in 1997, Cliffwood shareholders acquired a controlling interest in Texoil, Inc., where Mr. Lodzinski served as Chief Executive Officer and President. In 2001, Mr. Lodzinski was appointed Chief Executive Officer and President of AROC, Inc., to direct the restructuring and ultimate liquidation of that company. In 2003, AROC completed a monetization of oil and gas assets with an institutional investor and began a plan of liquidation in 2004. In 2004, Mr. Lodzinski formed Southern Bay Energy, LLC, the general partner of Southern Bay Oil & Gas, L.P., which acquired the residual assets of AROC, Inc., and he served as President of Southern Bay Energy, LLC upon its formation. The Southern Bay entities were merged into GeoResources in April 2007. Mr. Lodzinski has served as a director and member of the nominating and governance committee, audit committee and compensation committee of Yuma Energy, Inc. (“Yuma”) since April 2019 and previously served on its audit committee from September 2014 to October 2016 and its compensation committee from October 2016 to April 2019. On April 15, 2020, Yuma, together with its subsidiaries, filed voluntary Chapter 11 petitions for relief under the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. On October 20, 2020 the Bankruptcy Court issued an order to convert the Cases to a Chapter 7 liquidation. Mr. Lodzinski holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan.
Robert J. Anderson has served as our President and Chief Executive Officer since April 2020, having previously served as President since April 2018. From December 2014 through April 2018, he served as our Executive Vice President, Corporate Development and Engineering. Previously, he served in a similar capacity with Oak Valley from March 2013 until the closing of its strategic combination with the Company in December 2014. Prior to joining Oak Valley, he served from August 2012 to February 2013 as Executive Vice President and Chief Operating Officer of Halcón. Mr. Anderson was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012, ultimately serving as a director and Executive Vice President, Chief Operating Officer - Northern Region. He was involved in the formation of Southern Bay Energy in September 2004 as Vice President, Acquisitions until its merger with GeoResources in April 2007. From March 2004 to August 2004, Mr. Anderson was employed by AROC, a predecessor company to Southern Bay Energy, as Vice President, Acquisitions and Divestitures. Prior to March 2004 he was employed in technical and supervisory roles with Anadarko Petroleum Corporation, major oil companies including ARCO International/Vastar Resources, and independent oil companies, including Hugoton Energy, Hunt Oil and Pacific Enterprises Oil Company. His professional experience of over 30 years includes acquisition evaluation, reservoir and production engineering, field development, project economics, budgeting and planning, and capital markets. Mr. Anderson has a B.S. degree in Petroleum Engineering from the University of Wyoming and an MBA from the University of Denver.
Tony Oviedo has served as our Executive Vice President - Accounting and Administration (Principal Accounting Officer) since February 10, 2017. Mr. Oviedo has over 30 years of professional experience with both private and public companies. Prior to joining the Company, he was employed by GeoMet, Inc., where, since 2006, he served as the Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller. In addition, prior to joining GeoMet, Mr. Oviedo was employed by Resolution Performance Products, LLC, where he was Compliance Director and has held positions as Chief Accounting Officer, Controller, and Director of Financial Reporting with various companies in the oil and gas industry. Prior to the aforementioned experience, he served in the audit practice of KPMG LLP’s Energy Group. Mr. Oviedo holds a Bachelor’s degree in Business Administration with a concentration in accounting and tax from the University of Houston and is a Certified Public Accountant in the state of Texas.
Mark Lumpkin, Jr. has over 23 years of experience including over 16 years of oil and gas finance experience. He has served as our Executive Vice President and Chief Financial Officer since August 2017. Immediately prior to joining Earthstone, he served as Managing Director at RBC Capital Markets in the Oil and Gas Corporate Banking group, beginning in 2011 with a focus on upstream and midstream debt financing. From 2006 until 2011, he was employed by The Royal Bank of Scotland (“RBS”) in the Oil and Gas group within the Corporate and Investment Banking division, focusing primarily on the upstream subsector. Prior to RBS, he spent two years focused on capital markets and mergers and acquisitions primarily in the upstream
sector at a boutique investment bank. Mr. Lumpkin graduated with a B.A. degree in Economics from Louisiana State University and graduated with a Master of Business Administration degree with a Finance concentration from Tulane University.
Steven C. Collins is a petroleum engineer with over 30 years of operations and related experience. He has served as our Executive Vice President, Completions and Operations since December 2014. Previously, he served in a similar capacity with Oak Valley from its formation in December 2012 until the closing of its strategic combination with the Company in December 2014. Mr. Collins was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012 and directed field operations, including well completion, production and workover operations. Prior to employment by GeoResources, he served as Vice President of Operations for Southern Bay, AROC, and Texoil, and as a petroleum and operations engineer at Hunt Oil Company and Pacific Enterprises Oil Company. His experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, and the Mid-Continent. Mr. Collins graduated with a B.S. degree in Petroleum Engineering from the University of Texas.
Timothy D. Merrifield has over 39 years of oil and gas industry experience. He has served as our Executive Vice President, Geology and Geophysics since December 2014. Previously, he served in a similar capacity with Oak Valley from its formation in December 2012 until the closing of its strategic combination with the Company in December 2014. Prior to employment by Oak Valley, he served from August 2012 to November 2012 as a consultant to Halcón upon its merger with GeoResources, Inc. in August 2012. From April 2007 to August 2012, Mr. Merrifield led all geology and geophysics efforts at GeoResources. He has held previous roles at AROC, Force Energy, Great Western Resources and other independents. His domestic experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, New Mexico, Rocky Mountain States, and the Mid-Continent. In addition, he has international experience in Peru and the East Irish Sea. Mr. Merrifield attended Texas Tech University.
Available Information
Our principal executive offices are located at 1400 Woodloch Forest Drive, Suite 300, The Woodlands, Texas 77380. Our telephone number is (281) 298-4246. You can find more information about us at our website located at www.earthstoneenergy.com. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and any amendments to those reports are available free of charge on or through our website, which is not part of this report. These reports are available as soon as reasonably practicable after we electronically file these materials with, or furnish them to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Our business is subject to various risks and uncertainties in the ordinary course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our shares of Class A Common Stock, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Concerning Forward-Looking Statements” and other information included and incorporated by reference into this report.
Our business and operations have been and will likely continue to be adversely affected by the ongoing COVID-19 pandemic.
The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economies, including contributing to the reduced global and domestic demand for oil and natural gas, which has had and will likely continue to have an adverse effect on our business, financial condition and results of operations. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 could also negatively impact the availability of key personnel necessary to conduct our business. If COVID-19 continues to spread or the response to contain or mitigate the COVID-19 pandemic through the development and availability of effective treatments and vaccines, including the vaccines recently approved by the FDA for emergency use in the U.S., is unsuccessful, we could continue to experience material adverse effects on our business, financial condition and results of operations. Due to the rapid development and fluidity of this situation, we cannot make any prediction as to the ultimate material adverse impact of the COVID-19 pandemic on our business, financial condition and results of operations.
Oil, natural gas and natural gas liquids prices are volatile. Their prices at times since 2014 have adversely affected, and in the future may adversely affect, our business, financial condition and results of operations and our ability to meet our
capital expenditure obligations and financial commitments. Volatile and lower prices may also negatively impact our stock price.
The prices we receive for our oil, natural gas and natural gas liquids production heavily influence our revenues, profitability, access to capital and future rate of growth. These hydrocarbons are commodities, and therefore, their prices may be subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil, natural gas and natural gas liquids has been volatile. For example, during the period from January 1, 2014 through December 31, 2020, the WTI spot price for oil declined from a high of $107.95 per Bbl in June 2014 to -$36.98 per Bbl in April 2020. The Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu in February 2014 to a low of $1.33 per MMBtu in September 2020. During 2020, WTI spot prices ranged from -$36.98 to $63.27 per Bbl and the Henry Hub spot price of natural gas ranged from $1.33 to $3.14 per MMBtu. Likewise, natural gas liquids, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have experienced significant declines in realized prices since the fall of 2014. The prices we receive for oil, natural gas and natural gas liquids we produce and our production levels depend on numerous factors beyond our control, including:
•worldwide, regional and local economic and financial conditions impacting supply and demand;
•the level of global exploration, development and production;
•the level of global supplies, in particular due to supply growth from the United States;
•the price and quantity of oil, natural gas and NGLs imports to and exports from the U.S.;
•political conditions in or affecting other oil, natural gas and natural gas liquids producing countries and regions, including the current conflicts in the Middle East, Asia and Eastern Europe;
•actions of the OPEC and state-controlled oil companies relating to production and price controls;
•the extent to which U.S. shale producers become swing producers adding or subtracting to the world supply totals;
•future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;
•current and future regulations regarding well spacing;
•prevailing prices and pricing differentials on local oil, natural gas and natural gas liquids price indices in the areas in which we operate;
•localized and global supply and demand fundamentals and transportation, gathering and processing availability;
•weather conditions;
•technological advances affecting fuel economy, energy supply and energy consumption;
•the effect of energy conservation measures, alternative fuel requirements and increasing demand for alternatives to oil and natural gas;
•global or national health concerns, including health epidemics such as the COVID-19 pandemic at the beginning of 2020;
•the price and availability of alternative fuels; and
•domestic, local and foreign governmental regulation and taxes.
Lower oil, natural gas and natural gas liquids prices have and may continue to reduce our cash flows and borrowing capacity. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our hydrocarbon reserves as existing reserves are depleted. A decrease in prices could render development projects and producing properties uneconomic, potentially resulting in a loss of mineral leases. Low commodity prices have, at times, caused significant downward adjustments to our estimated proved reserves, and may cause us to make further downward adjustments in the future. Furthermore, our borrowing capacity could be significantly affected by decreased prices. A sustained decline in oil, natural gas and natural gas liquids prices could adversely impact our borrowing base in future borrowing base redeterminations, which could trigger repayment obligations under the Credit Agreement to the extent our outstanding borrowings exceed the redetermined borrowing base and could otherwise materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In addition, lower oil, natural gas and natural gas liquids gas prices may cause a decline in the market price of our shares.
As a result of low prices for oil, natural gas and natural gas liquids, we may be required to take significant future write-downs of the financial carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our proved and unproved properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to significantly write-down the financial carrying value of our oil and natural gas properties, which constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are recorded.
A write-down could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved oil and natural gas reserves, if operating costs or development costs increase over prior estimates, or if exploratory drilling is unsuccessful.
The capitalized costs of our oil and natural gas properties, on a field-by-field basis, may exceed the estimated future net cash flows of that field. If so, we would record impairment charges to reduce the capitalized costs of such field to our estimate of the field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce our earnings and stockholders’ equity and could adversely affect our stock price.
We periodically assess our properties for impairment based on future estimates of proved and non-proved reserves, oil and natural gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if price increases of oil and/or natural gas occur and in the event of increases in the quantity of our estimated proved reserves.
If oil, natural gas and natural gas liquids prices fall below current levels for an extended period of time and all other factors remain equal, we may incur impairment charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are recorded. See Note 7. Oil and Natural Gas Properties to the Notes to Consolidated Financial Statements included in this report for additional information.
Any significant reduction in our borrowing base under our Credit Agreement may negatively impact our liquidity and, consequently, our ability to fund our operations, including capital expenditures, and we may not have sufficient funds to repay borrowings under our Credit Agreement or any other obligation if required as a result of a borrowing base redetermination.
Availability under the Credit Agreement is currently subject to a borrowing base of $360.0 million, as increased with the closing of the IRM Acquisition on January 7, 2021. The borrowing base is subject to scheduled semiannual redeterminations (on or about May 1 and November 1), as well as other lender-elective borrowing base redeterminations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the Credit Agreement. Reductions in estimates of our oil, natural gas and natural gas liquids reserves may result in a reduction in our borrowing base under the Credit Agreement (if prices are kept constant). Reductions in our borrowing base under the Credit Agreement could also arise from other factors, including but not limited to:
•lower commodity prices or production;
•increased leverage ratios;
•inability to drill or unfavorable drilling results;
•changes in oil, natural gas and natural gas liquids reserve engineering techniques;
•increased operating and/or capital costs;
•the lenders’ inability to agree to an adequate borrowing base; or
•adverse changes in the lenders’ practices (including required regulatory changes) regarding estimation of reserves.
As of December 31, 2020, we had $115.0 million of borrowings outstanding under the Credit Agreement with a borrowing base of $240 million. When adjusted to include the IRM Acquisition on January 7, 2021, we had $260 million of long-term debt outstanding under the Credit Agreement with a borrowing base of $360 million. We may make further borrowings under the Credit Agreement in the future. Any significant reduction in our borrowing base under the Credit Agreement as a result of borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of operations and cash flows. Further, if the outstanding borrowings under the Credit Agreement were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess.
Unless we replace our reserves, our production and estimated reserves will decline, which may adversely affect our financial condition, results of operations and/or cash flows.
Producing oil and natural gas reservoirs are generally characterized by declining production rates that may vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well, particularly horizontal wells. Estimates of the decline rate of an oil or natural gas well are inherently imprecise and may be less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our estimated future oil and natural gas reserves and production and, therefore, our cash flows and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional
reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition and results of operations.
Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of those reserves.
This report contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by SEC regulations relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex and requires significant decisions, complex analyses and assumptions in evaluating available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Our actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance will likely materially affect the estimated quantities and the estimated value of our reserves. In addition, we may later adjust estimates of proved reserves to reflect production history, results of exploration and development activities, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
Quantities of estimated proved reserves are based on economic conditions in existence during the period of assessment. Changes to oil, natural gas and natural gas liquids prices in the markets for these commodities may shorten the economic lives of certain fields because it may become uneconomical to produce all recoverable reserves in such fields, which may reduce proved reserves estimates.
Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as revisions in the assumptions of future estimated cash flows of those reserves, may also trigger impairment losses on certain properties, which may result in non-cash charges to earnings. See Note 7. Oil and Natural Gas Properties to the Notes to Consolidated Financial Statements included in this report.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2020, approximately 51% of our estimated proved reserves were classified as proved undeveloped. The development of our estimated proved undeveloped reserves of 40,577 MBOE will require an estimated $285.1 million of development capital over the next five years. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on successful drilling and completion results, future commodity prices, costs and economic assumptions that align with our internal forecasts, as well as access to liquidity sources, such as the capital markets, the Credit Agreement and derivative contracts. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. Moreover, under the SEC regulations, we may be required to write down our proved undeveloped reserves if we do not drill or have a development plan to drill wells within a prescribed five-year period. The estimated reserve data assumes that we will make specified capital expenditures to timely develop our reserves. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with SEC regulations; however, actual capital expenditures may vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.
The standardized measure of discounted future net cash flows from our estimated proved reserves may not be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the standardized measure of discounted future net cash flows from our estimated proved reserves set forth in this report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2020 and 2019, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas unweighted arithmetic average prices without giving effect to derivative transactions and costs in effect as of the date of the estimate, holding prices and costs constant through the life of the properties. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as: the actual prices we receive for oil and natural gas; the actual cost of development and production expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation.
The timing of both our production and incurring expenses related to developing and producing oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the oil and natural gas industry in general. As a corporation, we are treated as a taxable entity for statutory income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the estimates included in this report which could have a material effect on the value of our estimated reserves.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our leaseholds. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Properties we acquire may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of a property. We may be required to assume the risk of the physical condition of properties in addition to the risk that they may not perform in accordance with our expectations. If properties we acquire do not produce as projected or have liabilities we were unable to identify, we could experience a decline in our reserves and production, which could adversely affect our business, financial condition and results of operations.
Future drilling and completion activities associated with identified drilling locations may be adversely affected by factors that could materially alter the occurrence or timing of their drilling and completion, which in certain instances could prevent production prior to the expiration date of mineral leases for such locations.
Although our management team has identified numerous potential drilling locations as a part of our long-range planning related to future drilling activities on our existing acreage, our ability to drill and develop these locations depends on a number of factors, which are beyond our control, including, the availability and cost of capital, oil, natural gas and natural gas liquids prices, drilling and production costs, the availability of drilling services and equipment, drilling results (including the impact of increased horizontal drilling density and longer laterals), lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory permits and approvals and other factors. In addition, we may alter the spacing between our anticipated drilling locations, which could impact the number of our drilling locations, the number of wells that we drill, and the volumes of oil and gas we ultimately recover. As such, our actual drilling and completion activities, may materially differ from those presently anticipated. Accordingly, it is uncertain to what degree that these potential drilling locations will be developed or if we will be able to produce significant oil, natural gas and natural gas liquids from these or any other potential drilling locations. Unless production is established, in accordance with the terms of mineral leases that are associated with these locations, such leases could expire.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.
Many of our properties are in reservoirs that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which 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 toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and
other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from a given pad, which may cause volatility in our operating results. In addition, problems affecting one pad could adversely affect production from all wells on such pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production.
The unavailability or high cost of equipment, supplies, personnel and oilfield services used to drill and complete wells could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which activity has increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items. In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted if the United States imposes tariffs on imported goods from countries where these goods are produced. Such shortages or cost increases could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Our acquisition, development and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could limit growth or lead to a decline in our reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition and development of oil and natural gas reserves. We expect to fund our 2021 capital expenditures with cash on hand, cash generated by operations, borrowings under the Credit Agreement and possibly through additional capital market transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of high-quality drilling rigs and other services and equipment and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our cash flow from operations and access to capital are subject to a number of variables, including: our proved reserves; the level of hydrocarbons we are able to produce from existing wells; the prices at which our production is sold; our ability to acquire, locate and produce reserves; and our ability to borrow under the Credit Agreement.
If our revenues or the borrowing base under the Credit Agreement decrease as a result of low oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. The failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production and would adversely affect our business, financial condition and results of operations.
A negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.
Much of the investor community has developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Some investors, including certain public and private fund management firms, pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and gas sector based on environmental, social and governance considerations. Certain other stakeholders have pressured private equity firms and commercial and investment banks to stop funding oil and gas projects. Such developments have resulted and could continue to result in downward pressure on the stock prices of oil and gas companies, including ours. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
We have incremental cash inflows and outflows as a result of our hedging activities. To the extent we are unable to obtain future hedges at attractive prices or our derivative activities are not effective, our cash flows and financial condition may be adversely impacted.
In an effort to achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we often enter into derivative instrument contracts for a portion of our oil and natural gas production, including swaps, collars, puts and basis swaps. We recognize all derivatives as either assets or liabilities, measured at fair value, and recognize changes in the fair value of derivatives in current earnings. Accordingly, our earnings may fluctuate significantly and our results of operations may be significantly and adversely affected because of changes in the fair market value of our derivative instruments. As our derivative instrument contracts expire, there is no assurance that we will be able to replace them comparably.
Derivative instruments can expose us to the risk of financial loss in varying circumstances, including, but not limited to, when: production is less than the volume covered by the derivative instruments; the counter-party to the derivative instrument defaults on its contractual obligations; there is an increase in the differential between the underlying price stated in the derivative instrument contract and actual prices received; or there are issues with regard to legal enforceability of such instruments.
For additional information regarding our hedging activities, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 6. Derivative Financial Instruments in the Notes to Consolidated Financial Statements included in this report for additional information.
The oil and natural gas industry is highly competitive, and our small size puts us at a disadvantage in competing for resources.
The oil and natural gas industry is highly competitive particularly in the Permian Basin of Texas where our properties and operations are concentrated. We compete with major integrated and larger independent oil and natural gas companies in seeking to acquire desirable oil and natural gas properties and leases and for the equipment and services required to develop and operate properties. Many of our competitors have financial and other resources that are substantially greater than ours, which makes acquisitions of acreage or producing properties at economic prices difficult. Significant competition also exists in attracting and retaining technical personnel, including geologists, geophysicists, engineers, landmen and other specialists, as well as financial and administrative personnel hence we may be at a competitive disadvantage to companies with larger financial resources than ours.
Failure to complete additional acquisitions could limit our potential growth.
Our future success is highly dependent on our ability to acquire and develop mineral leases and oil and gas properties with economically recoverable oil and natural gas reserves. Without continued successful acquisition, of economic development projects, our current estimated oil and natural gas reserves will decline due to continued production activities. Acquiring additional oil and natural gas properties, or businesses that own or operate such properties is an important component of our business strategy. If we identify an appropriate acquisition candidate, management may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. Our limited access to financial resources compared to larger, better capitalized companies may limit our ability to make future acquisitions. If we are unable to complete suitable acquisitions, it may be more difficult to replace and increase our reserves, and an inability to replace our reserves may have a material adverse effect on our financial condition and results of operations.
Acquisitions involve a number of risks, including the risk that we will discover unanticipated liabilities or other problems associated with the acquired business or property.
In assessing potential acquisitions, we consider information available in the public domain and information provided by the seller. In the event publicly available data is limited, then, by necessity, we may rely to a large extent on information that may only be available from the seller, particularly with respect to drilling and completion costs and practices, geological, geophysical and petrophysical data, detailed production data on existing wells, and other technical and cost data not available in the public domain. Accordingly, the review and evaluation of businesses or properties to be acquired may not uncover all existing or relevant data, obligations or actual or contingent liabilities that could adversely impact any business or property to be acquired and, hence, could adversely affect us as a result of the acquisition. These issues may be material and could include, among other things, unexpected environmental liabilities, title defects, unpaid royalties, taxes or other liabilities. If we acquire properties on an “as-is” basis, we may have limited or no remedies against the seller with respect to these types of problems.
The success of any acquisition that we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, assumptions related to future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are often inexact and subjective. As a result,
we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales or operations.
Our ability to achieve the benefits that we expect from an acquisition will also depend on our ability to efficiently integrate the acquired operations. Management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business opportunities and concerns. The challenges involved in the integration process may include retaining key employees and maintaining employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding acquired properties.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, including our drilling operations.
Oil and natural gas exploration, development and production activities are subject to numerous significant operating risks, including the possibility of:
•unanticipated, abnormally pressured formations;
•significant mechanical difficulties, such as stuck drilling and service tools and casing collapses;
•blowouts, fires and explosions;
•personal injuries and death;
•uninsured or underinsured losses; and
•environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination.
Any of these operating hazards could cause damage to properties, reduced cash flows, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, which could expose us to significant liabilities. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
The nature of our business and assets exposes us to significant compliance costs and liabilities.
Our operations involving the exploration, development and production of hydrocarbons are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment as well as protection of the environment, operational safety, and related employee health and safety matters. Laws and regulations applicable to us include those relating but not limited to the following: land use restrictions; delivery of our oil and natural gas to market; drilling bonds and other financial responsibility requirements; spacing of wells; air emissions; property unitization and pooling; habitat and endangered species protection, reclamation and remediation; containment and disposal of hazardous substances, oil field waste and other waste materials; drilling permits; use of saltwater injection wells, which affects the disposal of saltwater from our wells; safety precautions; prevention of oil spills; operational reporting; and taxation and royalties.
Compliance with these laws and regulations is a significant cost of doing business. Failure to comply with applicable laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; the issuance of injunctions that may restrict, inhibit or prohibit our operations; and claims of damages to property or persons.
Some environmental laws and regulations impose strict liability, which means that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of prior operators of properties we acquired or of other third parties. Similarly, some environmental laws and regulations impose joint and several liability, meaning that we could be held responsible for more than our share of a particular reclamation or other obligation, and potentially the entire obligation, where other parties were involved in the activity giving rise to the liability. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Similarly, our actual plugging and abandonment obligations may be more than our estimates. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters, but we estimate that they will be material. Environmental risks are generally not fully insurable.
Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or in the future plan to conduct operations.
Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
From time to time, for example, legislation has been proposed in Congress to amend the SDWA to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations. Further, legislation to amend the SDWA to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.
More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. For example, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters, and disposal or storage of fracturing wastewater in unlined pits. The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Extreme weather conditions could adversely affect our ability to conduct drilling, completion and production activities in the areas where we operate.
Our exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes or freezing temperatures, which may cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. Such extreme weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.
The adoption of climate change legislation or regulations restricting emission of greenhouse gases, investor pressure concerning climate-related disclosures, and lawsuits could result in increased operating costs and reduced demand for the oil and gas we produce as well as reductions in the availability of capital.
Studies have found that emission of certain gases, commonly referred to as greenhouse gases (“GHGs”), impact the earth’s climate. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict emissions of GHGs. On January 20, 2021, President Biden’s first day in office, he signed an executive order on climate action and reconvened an interagency working group to establish interim and final social costs of three GHGs: carbon dioxide, nitrous oxide, and methane. Carbon dioxide is released during the combustion of fossil fuels, including oil, natural gas, and NGLs, and methane is a primary component of natural gas. The Biden administration stated it will use updated social cost figures to inform federal regulations and major agency actions and to justify
aggressive climate action as the United States moves toward a “100% clean energy” economy with net-zero GHG emissions. These actions could result in increased costs and reduced demand for our products.
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 adopted regulations under existing provisions of the Federal Clean Air Act that establish Prevention of Significant Deterioration (“PSD”) and Title V permit reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD and/or Title V permits under EPA’s GHG Tailoring Rule for their GHG emissions also may be required to meet “Best Available Control Technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations. In recent proposed rulemaking, the EPA is widening the scope of annual GHG reporting to include not only activities associated with completion and workover of natural gas wells with hydraulic fracturing and activities associated with oil and natural gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines.
While the U.S. Congress has considered legislation to reduce emissions of GHGs in recent years, it has not adopted any significant GHG legislation. This is expected to change with the Democratic Party now in control of the House of Representatives, the Senate, and the office of the President. In the absence of federal GHG legislation, a number of state and regional efforts have emerged, aimed at tracking and/or reducing GHG emissions through cap-and-trade programs, which typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. Any future laws or regulations that require reporting of, or otherwise limit emissions of, GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, and monitor and report GHG emissions associated with our operations, any of which could increase our operating costs and could adversely affect demand for the oil and natural gas that we produce. At this time, it is not possible to quantify the impact of such future laws and regulations on our business.
Several policy makers and political candidates have made, or expressed support for, a variety of more comprehensive proposals, such as cap-and-trade or carbon tax programs, as well as the more sweeping “green new deal” resolutions the U.S. Congress introduced in early 2019. As generally proposed, the “green new deal” includes (i) a cap-and-trade program capping overall GHG emissions on an economy-wide basis and requiring major sources of GHG emissions or major fuel producers to acquire and surrender emission allowances and (ii) a carbon tax, which would impose taxes based on emissions from our operations and the downstream uses of our products. The “green new deal” calls for a 10-year national mobilization effort to, among other things, transition 100% of the U.S. power demand to zero-emission sources and overhaul the U.S. transportation systems so that GHG emissions are eliminated as much as is technologically feasible. The enactment of any such legislation would have a material adverse effect on our business and operations.
Our oil, natural gas and natural gas liquids are sold in a limited number of geographic markets so an oversupply in any of those areas could have a material negative effect on the price we receive.
Our oil, natural gas and natural gas liquids are primarily sold in two geographic markets in Texas which each have a fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with oil, natural gas and/or natural gas liquids, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations. There is a risk that refining capacity in the U.S. Gulf Coast may be insufficient to refine all of the light sweet crude oil being produced in the United States. If light sweet crude oil production remains at current levels or continues to increase, demand for our light crude oil production could result in widening price discounts to the world crude prices and potential shut-in of production due to a lack of sufficient markets despite the lift on prior restrictions on the exporting of oil and natural gas.
Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of oil and natural gas exploration and development companies and may adversely affect our operations and cash flows.
In past years, federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key federal and state income tax provisions currently available to oil and natural gas exploration and development companies. For example, President Biden has set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to, (i) an increase in the U.S. income tax rate applicable to corporations and (ii) the elimination of tax subsidies for fossil fuels. Congress could consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction. The passage of any
legislation as a result of these proposals and other similar changes in federal income tax laws or the imposition of new or increased taxes or fees on oil and natural gas extraction could adversely affect our operations and cash flows.
Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating results and prospects.
Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and natural gas liquids, which could have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, which is leading to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.
Any change to government regulation or administrative practices may have a negative impact on our ability to operate and our profitability.
Oil and natural gas operations are subject to substantial regulation under federal, state and local laws relating to the exploration for, and the development, upgrading, marketing, pricing, taxation, and transportation of, oil and natural gas and related products and other associated matters. Amendments to current laws and regulations governing operations and activities of oil and natural gas exploration and development operations could have a material adverse impact on our business. In addition, there can be no assurance that income tax laws, royalty regulations and government programs related to our oil and natural gas properties and the oil and natural gas industry generally will not be changed in a manner which may adversely affect our progress or cause delays.
Permits, leases, licenses, and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of our activities or, if granted, will not be cancelled or will be renewed upon expiration. There is no assurance that such permits, leases, licenses, and approvals will not contain terms and provisions which may adversely affect our exploration and development activities.
The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not own or control. If these facilities or systems are unavailable, our oil and natural gas production can be interrupted and our revenues reduced.
The marketability of our oil and natural gas production is dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation and processing facilities owned by third parties. In general, we will not control these facilities, and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to deliver to market the hydrocarbons we produce and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our hydrocarbons is dependent upon coordination among third parties that own transportation and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. This is more likely in areas with recent increased production, such as our Permian Basin area where we have significant development activities. These are risks for which we generally will not maintain insurance.
We operate or participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to our projects.
In some cases, we operate but own less than 100% of the working interest in the oil and natural gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and natural gas liquids prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely
have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.
Use of debt financing may adversely affect our strategy.
We may use debt to fund a portion of our future acquisition, development and/or operating activities. Any temporary or sustained inability to service or repay such debt will likely have a material adverse effect on our ability to access financing markets and pursue our operating strategies, as well as impair our ability to respond to adverse economic changes in oil and natural gas markets and the economy in general.
Because we cannot control activities on properties we do not operate, we cannot directly control the timing of exploitation. If we are unable to fund required capital expenditures with respect to non-operated properties, our interests in those properties may be reduced or forfeited.
Our ability to exercise influence over operations and costs for the properties we do not operate is limited. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to acquisition, exploration or development activities. The success and timing of development, exploitation or exploration activities on properties operated by others depend upon a number of factors that may be outside our control, including but not limited to: the timing and amount of capital expenditures; the operator’s expertise and financial resources; the approval of other participants in drilling wells; and the selection of technology.
Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with the project. If we are not willing or able to fund required capital expenditures relating to a project when required by the majority owner(s) or operator, our interests in the project may be reduced or forfeited. Also, we could be responsible for plugging and abandonment costs, as well as other liabilities in excess of our proportionate interest in the property.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, data, facilities and infrastructure may result in increased capital and operating costs. Costs for insurance may also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at all. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.
The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
Risks Related to the Ownership of our Class A Common Stock
We are a holding company and the sole manager of EEH. Our only material asset is our equity interest in EEH and, accordingly, we are dependent upon distributions from EEH to cover our corporate and other overhead expenses and pay taxes.
We are a holding company and the sole manager of EEH. We have no material assets other than our equity interest in EEH. We have no independent means of generating revenue. We expect EEH to reimburse us for our corporate and other overhead expenses, and to the extent EEH has available cash, we intend to cause EEH to make distributions to the holders of membership units of EEH (“EEH Units”), including us, in an amount sufficient to cover all applicable U.S. federal, state and local income taxes and non-U.S. tax liabilities of Earthstone, Lynden Corp and Lynden US, if any, at assumed tax rates. We will likely be limited, however, in our ability to cause EEH and its subsidiaries to make these and other distributions due to the restrictions under the Credit Agreement. To the extent that we need funds, and EEH or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.
Our principal stockholders hold substantial voting power of our Class A Common Stock and Class B Common Stock.
Holders of Class A Common Stock and our Class B Common Stock, $0.001 par value per share (“Class B Common Stock”), will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our Third Amended and Restated Certificate of Incorporation. Subsequent to the IRM Acquisition, EnCap and Warburg Parties may be deemed to beneficially own approximately 49.4% and 17.0%, respectively, of our voting interests and, along with their affiliates, could limit the ability of our other stockholders to approve transactions they may deem to be in the best interests of our Company or delaying or preventing changes in control or changes in our management.
As long as EnCap and certain of its affiliates continue to control a significant amount of our outstanding voting securities, they will have the authority to exercise significant influence over management and all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. Also, in any of these matters, the interests of our management team may differ or conflict with the interests of our stockholders. In addition, EnCap and its affiliates may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential acquisition candidates or industry partners. EnCap and its affiliates may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.
Bold Holdings (controlled by EnCap) and its permitted transferees have the right to exchange their EEH Units and shares of Class B Common Stock for our Class A Common Stock pursuant to the terms of the EEH LLC Agreement.
As of March 1, 2021, there were approximately 34.4 million shares of our Class A Common Stock that are issuable upon redemption or exchange of EEH Units and shares of Class B Common Stock that are held by Bold Holdings, a fund managed by EnCap, or its permitted transferees. Pursuant to the First Amended and Restated Limited Liability Company Agreement of EEH (the “EEH LLC Agreement”), subject to certain restrictions therein, holders of EEH Units and our Class B Common Stock are entitled to exchange such EEH Units and shares of Class B Common Stock for shares of our Class A Common Stock at any time. If so exercised, EnCap would own more than 50% of our Class A Common Stock and would therefore have the ability to control our Company.
Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity may dilute your ownership in us.
We may sell additional shares of Class A Common Stock or securities convertible into shares of our Class A Common Stock in subsequent offerings. We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock.
We have no plans to pay dividends on our Class A Common Stock. Stockholders may not receive funds without selling their shares.
We do not anticipate paying any cash dividends on our Class A Common Stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. In addition, the Credit Agreement does not allow EEH to
make any significant payments to us, which makes it highly unlikely that we would be in a position to pay cash dividends on our Class A Common Stock.
Our Board of Directors can, without stockholder approval, cause preferred stock to be issued on terms that could adversely affect our common stockholders.
Under our Third Amended and Restated Certificate of Incorporation, our Board is authorized to cause Earthstone to issue up to 20,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this report. Also, our Board, without stockholder approval, may determine the price, rights, preferences, privileges, and restrictions, including voting rights, of those shares. If the Board causes shares of preferred stock to be issued, the rights of the holders of our Class A Common Stock and Class B Common Stock would likely be subordinate to those of preferred holders and therefore could be adversely affected. The Board’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third-party to acquire a majority of our outstanding voting stock or otherwise seek to acquire us. Shares of preferred stock issued by us could include voting rights, or even super voting rights, which could shift the ability to control Earthstone to the holders of the preferred stock. Preferred stock could also have conversion rights into shares of Class A Common Stock at a discount to the market price of the Class A Common Stock which could negatively affect the market for our Class A Common Stock. In addition, preferred stock could have preference in the event of liquidation of Earthstone, which means that the holders of preferred stock would be entitled to receive the net assets of Earthstone distributed in liquidation before the Class A common stockholders receive any distribution of the liquidated assets. We have no current plans to issue any shares of preferred stock.
The price of our Class A Common Stock may fluctuate significantly, which could negatively affect us and holders of our Class A Common Stock.
The trading price of our Class A Common Stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. Adverse events including changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance could negatively impact the market price of our Class A Common Stock. General market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our Class A Common Stock.
Anti-takeover provisions could make a third-party acquisition difficult.
Our Third Amended and Restated Certificate of Incorporation provides for a classified board of directors, with each member serving a three-year term. Provisions in our Third Amended and Restated Certificate of Incorporation could make it more difficult for a third-party to acquire us without the approval of our Board. In addition, the Delaware corporate statutes also contain certain provisions that could make an acquisition by a third-party more difficult.
Our stockholders may act by unilateral written consent.
Under our Third Amended and Restated Certificate of Incorporation, any action required to be taken at any annual or special meeting of our stockholders, or any action which may be taken at any annual or special meeting of such stockholders, may be taken without a meeting, without prior notice and without a vote, if a consent in writing, setting forth the action so taken, is signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Thus, consents of this type can be effected without the participation or input of minority stockholders.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
Summary of Oil and Gas Properties
Midland Basin
As of December 31, 2020, we had approximately 27,900 net acres in the core of the Midland Basin that are highly contiguous on a project-by-project basis which allow us to drill multi-well pads. Of this acreage, 78% is operated and 22% is non-operated. We hold an approximate 93% working interest in our operated acreage and an approximate 40% working interest in our non-operated acreage. Our operated acreage in the Midland Basin, consisting of approximately 21,800 net acres, is primarily located
in Reagan, Upton and Midland counties. Our non-operated acreage in the Midland Basin, consisting of approximately 6,100 net acres, is located primarily in Howard, Glasscock, Martin, Midland and Reagan counties.
With 407 potential gross operated horizontal drilling locations, largely de-risked, the vast majority of which are in various benches of the Wolfcamp and the Spraberry formations, in the Midland Basin as of December 31, 2020, we are focused on developmental drilling and completion operations in the area. As a result of the IRM Acquisition, we added 43,400 additional net acres in the Midland Basin of which 99% is operated and 1% is non-operated, as well as adding 70 potential gross horizontal drilling locations on core acreage located in Midland and Ector counties. We continue to pursue acreage trades or bolt-on acreage acquisitions in the Midland Basin with the intent of increasing our operated acreage and drilling inventory, drilling and completing longer laterals and realizing greater operating efficiencies.
During 2020, we completed and began producing from 9 gross / 9 net operated wells and 15 gross / 3.5 net non-operated wells. We exited 2020 with 5 gross / 3.7 net wells that were drilled and awaiting completion. We recently completed these wells and anticipate turning them to sales before the end of March 2021.
We recently commenced our 2021 drilling program with the deployment of a rig in Midland County. After drilling on a three-well pad in the Hamman project, we expect to drill a four-well pad on the recently acquired IRM Spanish Pearl project. We anticipate moving the rig to Upton County and drilling 10-11 wells. Consistent with previously released guidance, we anticipate drilling 16 gross / 14.8 net operated wells and spudding an additional 5 gross / 3.7 net operated wells during 2021.
Eagle Ford Trend
As of December 31, 2020, we held approximately 26,400 gross (12,500 net) leasehold acres primarily in Fayette, Gonzales and Karnes counties, Texas. The acreage is located in the crude oil window of the Eagle Ford shale trend of south Texas and is prospective for the Eagle Ford, Austin Chalk and Upper Eagle Ford formations. Our working interests range from approximately 12% to 67%.
As of December 31, 2020, we operated 103 gross Eagle Ford wells and 12 gross Austin Chalk wells and had non-operated interests in five gross producing Eagle Ford wells and one gross producing Austin Chalk wells. We have identified a total of 26 potential gross Eagle Ford drilling locations in this acreage. In addition, because our acreage position is prospective for the Austin Chalk and Upper Eagle Ford formations, we may have additional future economic locations. The majority of our acreage is covered by an approximately 173 square mile 3-D seismic survey.
Oil and Natural Gas Reserves
As of December 31, 2020, all of our oil and natural gas reserves were located in the state of Texas. We expect to further develop these properties through additional drilling and completion operations. Our reserve estimates have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. The scope and results of CG&A’s procedures are summarized in a letter which is included as an exhibit to this report. For further information on estimated reserves, including information on estimated future net cash flows and the standardized measure of discounted future net cash flows, please refer to the Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) in Part II, Item 8 of the Notes to Consolidated Financial Statements of this report.
As of December 31, 2020, our estimated proved reserves totaled 78,875 MBOE and had a PV-10 value of approximately $473.4 million (reconciled in “Non-GAAP Measures” below) and a Standardized Measure of Discounted Future Net Cash Flows of approximately $460.9 million, all of which relate to our properties in Texas. We incurred approximately $66.8 million in capital expenditures, primarily drilling and completion costs, during 2020. We expect to further develop our properties through additional drilling.
2020 Activity in Proved Reserves
From January 1, 2020 to December 31, 2020, our total estimated proved reserves decreased 16% from 94,336 MBOE to 78,875 MBOE. Of that, estimated proved developed reserves increased 21% from 31,521 MBOE to 38,298 MBOE and estimated proved undeveloped reserves decreased 35% from 62,815 MBOE to 40,577 MBOE. The overall proved reserve decreases were primarily attributable to negative revisions due to price which included the reclassification of 11,913 MBOE of reserves from proved undeveloped to non-proved due to the five-year development rule.
Proved Reserves as of December 31, 2020
The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquids reserves as of December 31, 2020, based on the annual reserve estimate prepared by CG&A. In preparing this reserve report, CG&A evaluated 100% of our properties at December 31, 2020. The prices used in estimating proved reserves are based on the unweighted arithmetic average
of the first-day-of-the-month price for each month within the 12-month period for the year. All prices and costs associated with operating wells were held constant in accordance with the SEC guidelines.
Our proved reserve categories as of December 31, 2020 are summarized in the table below:
Oil
(MBbl) Natural Gas
(MMcf) NGLs
(MBbl) Total
(MBOE)(2)
% of Total
Proved Undiscounted Future Net Cash Flows
($ in thousands) PV-10
($ in thousands) Standardized Measure of Discounted Future Net Cash Flows
($ in thousands) Future Capital Expenditures
($ in thousands)
PDP 18,876 55,752 10,123 38,291 49 % $ 557,361 $ 329,362 $ 320,627 $ -
PUD 21,212 55,450 10,123 40,577 51 % 426,340 144,047 140,226 285,088
Total proved (1)
40,088 111,202 20,246 78,868 100 % $ 983,701 $ 473,409 $ 460,853 $ 285,088
(1)Includes 21.5 MMBbl of oil, 59.6 Bcf of natural gas and 10.8 MMBbl of NGLs reserves attributable to noncontrolling interests. Additionally, $253.6 million of PV-10 and $246.9 million of standardized measure of discounted future net cash flows were attributable to noncontrolling interests.
(2)Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE).
Non-GAAP Measures
PV-10
PV-10 is a non-GAAP measure that differs from a measure under the accounting principles generally accepted in the United States (“GAAP”) known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. Management believes that the presentation of the PV-10 value of its oil and natural gas properties is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. We believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies because the timing and quantification of future income taxes is dependent on company-specific factors, many of which are difficult to determine. For these reasons, management uses and believes that the industry generally uses the PV-10 measure in evaluating and comparing acquisition candidates and assessing the potential rate of return on investments in oil and natural gas properties. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows (in thousands):
Present value of estimated future net revenues (PV-10) (1)
$ 473,409
Future income taxes, discounted at 10% (12,556)
Standardized measure of discounted future net cash flows (2)
$ 460,853
(1)Includes $253.6 million attributable to noncontrolling interests.
(2)Includes $246.9 million attributable to noncontrolling interests.
Free Cash Flow
Free cash flow is a measure that we use as an indicator of our ability to fund our development activities. We define free cash flow as Adjusted EBITDAX (defined below), less interest expense, less accrual-based capital expenditures.
Adjusted EBITDAX
The non-GAAP financial measure of Adjusted EBITDAX, as calculated by us below, is intended to provide readers with meaningful information that supplements our financial statements prepared in accordance with GAAP. Further, this non-GAAP measure should only be considered in conjunction with financial statements and disclosures prepared in accordance with GAAP and should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of financial position or results of operations. Adjusted EBITDAX is presented herein and
reconciled from the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator.
We define “Adjusted EBITDAX” as net income plus, when applicable, accretion of asset retirement obligations; impairment expense; depletion, depreciation and amortization; interest expense, net; transaction costs; (gain) on sale of oil and gas properties, net; exploration expense; unrealized loss (gain) on derivative contracts; stock-based compensation (non-cash); and income tax benefit.
Our Adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net (loss) income as an indicator of operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure and to assess the financial performance of our assets and our Company without regard to capital structure or historical cost basis.
Reserve Quantity Information
The following table illustrates our estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2020 and 2019, are based on the respective 12-month unweighted average of the first of the month prices of the WTI spot prices which equates to $39.57 per barrel and $55.69 per barrel, respectively. The natural gas prices as of December 31, 2020 and 2019 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $1.99 per MMBtu and $2.58 per MMBtu, respectively. The natural gas liquids prices used to value reserves as of December 31, 2020 and 2019 averaged $11.61 per barrel and $16.17 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials, resulting in the aforementioned oil, natural gas and natural gas liquids reserves as of December 31, 2020 being valued using prices of $38.90 per barrel, $0.97 per MMBtu and $11.61 per barrel, respectively. All prices are held constant in accordance with SEC guidelines.
A summary of our changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2020 and 2019 are as follows:
Oil
(MBbl) Natural Gas
(MMcf) NGLs
(MBbl) Total
(MBOE)
Balance - December 31, 2018 59,034 113,217 20,943 98,847
Extensions and discoveries 3,598 4,476 721 5,065
Sales of minerals in place (31) (4) (1) (32)
Production (3,086) (4,760) (1,022) (4,902)
Revision to previous estimates (6,865) (4,939) 3,047 (4,642)
Balance - December 31, 2019 52,650 107,990 23,688 94,336
Extensions and discoveries 420 1,258 230 860
Production (3,180) (7,282) (1,237) (5,630)
Revision to previous estimates (9,800) 9,249 (2,432) (10,691)
Balance - December 31, 2020 40,090 111,215 20,249 78,875
Proved developed reserves:
December 31, 2018 14,325 26,110 4,969 23,646
December 31, 2019 18,220 35,120 7,447 31,521
December 31, 2020 18,878 55,764 10,125 38,298
Proved undeveloped reserves:
December 31, 2018 44,709 87,107 15,974 75,201
December 31, 2019 34,430 72,870 16,241 62,815
December 31, 2020 21,212 55,450 10,123 40,577
The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2020 and 2019:
As of December 31, 2020 Oil
(MBbl) Natural Gas
(MMcf) NGLs
(MBbl) Total
(MBOE)
Proved developed 10,113 29,873 5,424 20,516
Proved undeveloped 11,363 29,704 5,423 21,737
Total proved 21,476 59,577 10,847 42,253
As of December 31, 2019 Oil
(MBbl) Natural Gas
(MMcf) NGLs
(MBbl) Total
(MBOE)
Proved developed 9,933 19,146 4,060 17,183
Proved undeveloped 18,769 39,724 8,853 34,243
Total proved 28,702 58,870 12,913 51,426
Notable changes in proved reserves for the year ended December 31, 2020 included the following:
•Extensions and discoveries. In 2020, total extensions and discoveries of 860.0 MBOE was the result of successful drilling results and well performance primarily related to the Midland Basin.
•Revision to previous estimates. In 2020, the downward revisions of prior reserves of 10.7 MMBOE were primarily attributable to negative revisions due to price which included the reclassification of 11.9 MMBOE of reserves from proved undeveloped to non-proved due to the five-year development rule.
Notable changes in proved reserves for the year ended December 31, 2019 included the following:
•Extensions and discoveries. In 2019, total extensions and discoveries of 5.1 MMBOE was a result of successful drilling results and well performance primarily related to the Midland Basin.
•Sales of minerals in place. Sales of minerals in place totaled 32.0 MBOE during 2019, resulting from the disposition of certain non-operated properties in the Midland Basin. See Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.
•Revision to previous estimates. In 2019, the downward revisions of prior reserves of 4.6 MMBOE were primarily due to reduced commodity prices.
Proved Undeveloped Reserves
Proved undeveloped reserves (“PUDs”) decreased from 62,815 MBOE to 40,577 MBOE or 35%, as of December 31, 2020 compared to December 31, 2019. PUDs represent 51% of our total proved reserves. Certain previously booked PUDs were reclassified as proved developed reserves due to successful drilling efforts. Revisions of prior estimates include certain PUDs that were reclassified to unproved categories due to development plan changes and increased well spacing. In accordance with our December 31, 2020 year-end independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within the five years of original classification.
Changes in our PUD reserves for the years ended December 31, 2020 and 2019 were as follows (in MBOE):
Proved undeveloped reserves at December 31, 2018(1) 75,201
Conversions to developed (10,254)
Extensions and discoveries 1,230
Revision to previous estimates (3,362)
Proved undeveloped reserves at December 31, 2019 (2) 62,815
Conversions to developed (8,200)
Revision to previous estimates (14,038)
Proved undeveloped reserves at December 31, 2020 (3) 40,577
(1)Includes 41,560 MBOE attributable to noncontrolling interests.
(2)Includes 34,243 MBOE attributable to noncontrolling interests.
(3)Includes 21,737 MBOE attributable to noncontrolling interests.
2020 Changes in Proved Undeveloped Reserves
Conversions to developed. In our year-end 2019 plan to develop its PUDs within five years, we estimated that $111.1 million of capital would be expended in 2020 for the conversion of 28 gross / 17.6 net PUDs to add 11.3 MMBOE. In 2020, due to unforeseeable conditions described above, we spent $67.8 million to convert 18 gross / 10.3 net PUDs adding 8.2 MMBOE to developed reserves.
Revision to previous estimates. We maintain a five-year development plan, reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations. In response to lower commodity prices, we reduced the pace of activity in our five-year development plan. This resulted in the reclassification of 11.9 MMBOE of reserves from proved undeveloped to non-proved during the year ended December 31, 2020 due to the five-year development rule. Based on our then-current acreage position, strip prices, anticipated well economics, and our development plans at the time these reserves were classified as proved, we believe the previous classification of these locations as proved undeveloped was appropriate. The remaining revisions of 2.1 MMBOE were primarily due to reduced commodity prices.
2019 Changes in Proved Undeveloped Reserves
Conversions to developed. In our year-end 2018 plan to develop our PUDs within five years, we estimated that $103.8 million of capital would be expended in 2019 for the conversion of 30 gross / 12.3 net PUDs to add 9.9 MMBOE, which was consistent with the $111.5 million actually spent to convert 32 gross / 13.4 net PUDs adding 10.3 MMBOE to developed reserves.
Extensions and discoveries. Additionally, 1.2 MMBOE were added as extensions and discoveries due to successful drilling results on our acreage positions because of the wells we drilled. The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to our acreage.
Revision to previous estimates. Revisions of 3.4 MMBOE were primarily due to reduced commodity prices.
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
The following table sets forth the estimated timing and cash flows of developing our proved undeveloped reserves at December 31, 2020 ($ in thousands):
Years Ended December 31, (1)
Future Production (MBOE) (2)
Future Cash Inflows (3)
Future Production Costs Future Development Costs Future Net Cash Flows
2021 419 $ 13,310 $ 2,217 $ 41,120 $ (30,027)
2022 2,484 77,303 12,361 106,245 (41,303)
2023 4,099 118,811 20,597 101,700 (3,486)
2024 4,587 124,723 23,295 36,023 65,405
2025 3,189 80,363 16,777 - 63,586
Thereafter 25,799 580,758 208,593 - 372,165
Total 40,577 $ 995,268 $ 283,840 $ 285,088 $ 426,340
(1)Beginning in 2021 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects from the results of proved undeveloped drilling from previous years. These production volumes, inflows, expenses, development costs and cash flows are limited to the PUD reserves and do not include any production or cash flows from the Proved Developed category which will also help to fund our capital program.
(2)Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE).
(3)Computation is based on SEC pricing of (i) $38.90 per Bbl (WTI-Cushing oil spot prices, adjusted for differentials), (ii) $0.97 per Mcf (Henry Hub spot natural gas price), as adjusted for location and quality by property and (iii) $11.61 per Bbl for natural gas liquids.
PUD reserves are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital expenditures are required, such as from drilled but uncompleted (DUC) wells. Our development plan contemplates production to commence from all these wells by 2024.
Historically, our drilling programs have been substantially funded from our cash flow and borrowings under our Credit Agreement. Based on current commodity prices and our current expectations over the next five years of our cash flows and
drilling programs, which includes drilling of proved undeveloped and unproven locations, we believe that we can continue to substantially fund our drilling activities from our cash flow and with borrowings under the Credit Agreement.
Preparation of Reserve Estimates
We engaged an independent petroleum engineering consulting firm, CG&A, to prepare our annual reserve estimates and we have relied on CG&A’s expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines.
The technical person primarily responsible for the preparation of the reserve report is Mr. W. Todd Brooker, President of CG&A. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. Mr. Brooker is a Registered Professional Engineer in the State of Texas (License No. 83462) and has more than 25 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of Petroleum Engineers.
Geoffrey A. Vernon, our Vice President of Reservoir Engineering and A&D, is responsible for reservoir engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing CG&A during the preparation of our annual reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Chemical Engineering from Texas Tech University in 2007; a Master of Business Administration degree from Rice University in 2014; member of the Society of Petroleum Engineers since 2007; and more than 13 years of practical experience in estimating and evaluating reserve information with more than nine of those years being in charge of estimating and evaluating reserves.
We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest and production data. The relevant field and reservoir technical information, which is updated, at least, annually, is assessed for validity when CG&A has technical meetings with our engineers, geologists, operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Control - Integrated Framework, (2013 Version) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to our internal controls over financial reporting, and they are incorporated in our reserve database as well and verified internally by our personnel to ensure their accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, CG&A meets with our technical personnel to review field performance and future development plans in order to further verify the validity of estimates. Following these reviews, the reserve database is furnished to CG&A so that it can prepare its independent reserve estimates and final report. The reserve estimates prepared by CG&A are reviewed and compared to our internal estimates by our Vice President of Reservoir Engineering and A&D. Material reserve estimation differences are reviewed between CG&A and us, and additional data is provided to address the differences. If the supporting documentation will not justify additional changes, the CG&A reserves are accepted. In the event that additional data supports a reserve estimation adjustment, CG&A will analyze the additional data, and may make changes it solely deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final estimates provided by CG&A.
Net Oil, Natural Gas and Natural Gas Liquids Production, Average Price and Average Production Cost
The net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2020 and 2019, the average sales price per unit sold (excluding hedges) and the average production cost per unit are presented below:
Years Ended December 31,
2020 2019
Sales Volumes:
Oil (MBbl) 3,180 3,086
Natural gas (MMcf) 7,282 4,760
Natural gas liquids (MBbl) 1,198 1,022
Barrels of oil equivalent (MBOE)* 5,591 4,902
Average daily production (BOE per day) 15,276 13,429
Average prices realized:**
Oil (per Bbl) $ 37.85 $ 55.71
Natural gas (per Mcf) $ 1.18 $ 0.82
Natural gas liquids (per Bbl) $ 13.03 $ 15.09
Barrels of oil equivalent (per BOE) $ 25.85 $ 39.02
Production cost per BOE $ 5.21 $ 5.85
* Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE).
** Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting. Our derivatives for 2020 and 2019 have been marked-to-market in our Consolidated Statements of Operations and both the realized and unrealized amounts are reported as other income/expense.
The following tables summarize the net quantities of oil, natural gas and natural gas liquids produced and sold by us, the average sales price per unit sold (excluding hedges) and the average production cost per unit for each of our core areas for the years ended December 31, 2020 and 2019.
Midland Basin
Years Ended December 31,
2020 2019
Sales Volumes:
Oil (MBbl) 2,687 2,599
Natural gas (MMcf) 7,079 4,558
Natural gas liquids (MBbl) 1,141 965
Barrels of oil equivalent (MBOE)* 5,007 4,324
Average daily production (BOE per day) 13,681 11,846
Average prices realized:**
Oil (per Bbl) $ 37.68 $ 55.05
Natural gas (per Mcf) $ 1.15 $ 0.75
Natural gas liquids (per Bbl) $ 13.08 $ 15.07
Barrels of oil equivalent (per BOE) $ 24.83 $ 37.25
Production cost per BOE $ 4.81 $ 5.22
* Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE).
** Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting.
Eagle Ford Trend
Years Ended December 31,
2020 2019
Sales Volumes:
Oil (MBbl) 493 487
Natural gas (MMcf) 204 202
Natural gas liquids (MBbl) 57 57
Barrels of oil equivalent (MBOE)* 584 578
Average daily production (BOE per day) 1,595 1,583
Average prices realized:**
Oil (per Bbl) $ 38.82 $ 59.20
Natural gas (per Mcf) $ 1.95 $ 2.43
Natural gas liquids (per Bbl) $ 11.96 $ 15.41
Barrels of oil equivalent (per BOE) $ 34.62 $ 52.29
Production cost per BOE $ 8.61 $ 10.58
* Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE).
** Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting.
Gross and Net Productive Wells
The following table summarizes our gross and net productive oil and natural gas wells by area as of December 31, 2020. A net well represents our percentage of ownership of a gross well.
Oil Natural Gas Total
Gross Net Gross Net Gross Net
Midland Basin 226 125 2 1 228 126
Eagle Ford Trend 121 52 - - 121 52
Acreage
The following table summarizes our gross and net developed and undeveloped acreage by area and state as of December 31, 2020. Net acreage represents our percentage ownership of gross acreage.
Developed Undeveloped Total
Gross Net Gross Net Gross Net
Midland Basin 8,450 5,188 30,325 22,713 38,775 27,901
Eagle Ford Trend 23,537 10,451 2,882 2,025 26,419 12,476
Texas 31,987 15,639 33,207 24,738 65,194 40,377
The following table summarizes, as of December 31, 2020, the portion of our gross and net acreage subject to expiration over the next three years if not successfully developed or renewed.
Expiring Acreage
2021 2022 2023 Total
Gross Net Gross Net Gross Net Gross Net
Midland Basin 121 10 721 495 - - 842 505
Eagle Ford Trend 926 421 4,036 1,471 49 41 5,011 1,933
Total 1,047 431 4,757 1,966 49 41 5,853 2,438
Approximately 97% of the Midland Basin net acreage is held by production and approximately 84% of the Eagle Ford net acreage is held by production. On a combined basis, our total net acreage is approximately 93% held by production.
Drilling Activities
The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed in the periods indicated.
Years Ended December 31,
2020 2019
Gross Net Gross Net
Development wells:
Productive 24 13 42 21
Dry(1)
- - 1 -
Exploratory wells:
Productive - - - -
Dry - - - -
Total wells:
Productive 24 13 42 21
Dry - - 1 -
Total 24 13 43 21
(1)The dry hole category includes one gross (0.2 net) non-operated well that was unsuccessful due to mechanical issues.
The figures in the table above do not include 5 gross wells (3.7 net) that were drilled and uncompleted or in the process of being completed at December 31, 2020, all of which are classified as PUDs as of that date and are expected to begin producing in the first quarter of 2021.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
In the ordinary course of business, we may be involved in litigation and claims arising out of our operations. As of December 31, 2020, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.
A description of our legal proceedings is included in Note. 16. Commitments and Contingencies in the Notes to Consolidated Financial Statements included in Item 8 of this report.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Shares of our Class A Common Stock are listed on the NYSE under the symbol “ESTE.”
Holders
As of March 1, 2021, there were approximately 3,900 holders of record of our Class A Common Stock and 13 holders of record of our Class B Common Stock. There is no public market for our Class B Common Stock.
Dividends
We have never paid dividends on our Class A Common Stock or Class B Common Stock and do not have current plans to pay a dividend. Furthermore, the Credit Agreement restricts the payment of cash dividends. The payment of future cash dividends on our Class A Common Stock, if any, will be reviewed periodically by our Board and will depend upon, but not be limited to, our financial condition, funds available for operations, the amount of anticipated capital and other expenditures, our future business prospects and any restrictions imposed by our present or future financing arrangements.
Repurchase of Equity Securities
The following table sets forth information regarding our acquisition of shares of Class A Common Stock for the periods presented:
Total Number of Shares Purchased (1)
Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plan or Programs
October 2020 - - - -
November 2020 - - - -
December 2020 56,151 $ 5.42 - -
(1)All of the shares were surrendered by employees (via net settlement) in satisfaction of tax obligations upon the vesting of restricted stock unit awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our Class A Common Stock.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and therefore are not required to provide the information required under this item.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This discussion and other items in this Annual Report on Form 10-K contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to numerous risks, uncertainties and assumptions. See Cautionary Statement Concerning Forward-Looking Statements in this report. Certain of these risks are summarized in this report under Item 1A. Risk Factors, which you should read carefully in connection with our forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.
Overview
We are a growth-oriented independent oil and gas company engaged in the economic acquisition and development of oil and gas reserves through activities that include the acquisition, drilling and development of undeveloped leases, asset and corporate
acquisitions and mergers. Our operations are all in the upstream segment of the oil and natural gas industry and all our properties are onshore in the United States. At present, our assets are located in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas.
Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Corp, and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden US and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH’s members other than Earthstone and Lynden US (collectively, the “Company” “our,” “we,” “us,” or similar terms).
Midland Basin Acquisition
On January 7, 2021, Earthstone Energy, Inc. (“Earthstone” or the “Company”), Earthstone Energy Holdings, LLC, a subsidiary of the Company (“EEH” and collectively with Earthstone, the “Buyer”), Independence Resources Holdings, LLC (“Independence”), and Independence Resources Manager, LLC (“Independence Manager” and collectively with Independence, the “Seller”) consummated the transactions contemplated in the Purchase and Sale Agreement dated December 17, 2020 (the “Purchase Agreement”) that was previously reported on Form 8-K filed with the SEC on December 22, 2020. The Seller was unaffiliated with the Company. At the closing of the Purchase Agreement, among other things, EEH acquired (the “Acquisition”) all of the issued and outstanding limited liability company interests in certain wholly owned subsidiaries of Independence and Independence Manager (collectively, the “Acquired Entities”) for aggregate consideration consisting of the following: (i) an aggregate amount of cash from EEH equal to approximately $131.2 million (the “Cash Consideration”) and (ii) 12,719,594 shares of the Company’s Class A Common Stock issued to Independence (such shares, the “Acquisition Shares,” and such issuance, the “Stock Issuance”). As a result of the Stock Issuance, Earthstone is no longer considered a controlled company within the meaning of the NYSE rules.
Amendment to Credit Agreement - In preparation for the IRM Acquisition, on December 17, 2020, Earthstone, EEH, as Borrower, Wells Fargo Bank, National Association (“Wells Fargo”), as Administrative Agent, the guarantors party thereto, and the lenders party thereto (the “Lenders”) entered into an amendment (the “Amendment”) to the credit agreement dated November 21, 2019, by and among EEH, as Borrower, Earthstone, as Parent, Wells Fargo, as Administrative Agent and Issuing Bank, BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, and the Lenders party thereto (together with all amendments or other modifications, the “Credit Agreement”). The Amendment was effective upon the closing of the IRM Acquisition. Among other things, the Amendment (i) joined certain financial institutions as additional lenders, increased the borrowing base from $240.0 million to $360.0 million, (ii) increased the interest rate on outstanding borrowings; and (iii) adjusted some of the financial covenants.
Liquidity Update
As of March 1, 2021, we had $10.1 million in cash and $227.5 million of long-term debt outstanding under our Credit Agreement, as amended, with a borrowing base of $360 million. With the $132.5 million of undrawn borrowing base capacity and $10.1 million in cash, we had total liquidity of approximately $142.6 million.
Areas of Operation
At present, our primary efforts are concentrated in the Midland Basin of west Texas, a high oil and liquids rich resource basin that provides us with multiple horizontal targets, extensive production histories, long-lived reserves and historically high drilling success rates.
Midland Basin
We believe that the Midland Basin continues to have attractive economics and we expect to continue growing our footprint through development drilling, acreage trades, asset acquisitions, and corporate merger and acquisition opportunities.
We continue to be active in acreage trades and acquisitions in the Midland Basin which generally allow for longer laterals, increased operated inventory and greater operating efficiency.
During 2020, we completed and began producing from 9 gross / 9 net operated wells and 15 gross / 3.5 net non-operated wells. We exited 2020 with 5 gross / 3.7 net wells that were drilled and awaiting completion. We recently completed these wells and anticipate turning them to sales before the end of March 2021.
We recently commenced our 2021 drilling program with the deployment of a rig in Midland County. After drilling on a three-well pad in the Hamman project, we expect to drill a four-well pad on the recently acquired IRM Spanish Pearl project. We
anticipate moving the rig to Upton County and drilling 10-11 wells. Consistent with previously released guidance, we anticipate drilling 16 gross / 14.8 net operated wells and spudding an additional 5 gross / 3.7 net operated wells during 2021.
Additionally, we are focused on efficiently integrating the recently acquired IRM assets into our operations. As a result of the IRM Acquisition, we added 43,400 additional net acres in the Midland Basin of which 99% is operated and 1% is non-operated, as well as adding 70 potential gross horizontal drilling locations on core acreage located in Midland and Ector counties.
Impairments
We recorded impairments in 2020 as follows:
($ in thousands) Eagle Ford Trend Midland Basin Corporate Total
Proved properties $ 25,252 $ - $ - $ 25,252
Unproved properties 11,311 - - 11,311
Acreage expirations (1) 2,400 7,915 - 10,315
Goodwill - - 17,620 17,620
$ 38,963 $ 7,915 $ 17,620 $ 64,498
(1)Impairments in unproved properties resulting from acreage deemed expired (not planned to be renewed).
Results of Operations
Year ended December 31, 2020 compared to the year ended December 31, 2019
Years Ended December 31,
2020 2019 Change
Sales volumes:
Oil (MBbl) 3,180 3,086 3 %
Natural gas (MMcf) 7,282 4,760 53 %
Natural gas liquids (MBbl) 1,198 1,022 17 %
Barrels of oil equivalent (MBOE) (1)
5,591 4,902 14 %
Average daily production (BOE per day) 15,276 13,429 14 %
Average prices realized:
Oil (per Bbl) $ 37.85 $ 55.71 (32) %
Natural gas (per Mcf) $ 1.18 $ 0.82 44 %
Natural gas liquids (per Bbl) $ 13.03 $ 15.09 (14) %
Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl) $ 54.95 $ 59.82 (8) %
Natural gas ($/Mcf) $ 1.42 $ 1.49 (5) %
Natural gas liquids ($/Bbl) $ 13.03 $ 15.09 (14) %
(In thousands)
Oil revenues $ 120,355 $ 171,925 (30) %
Natural gas revenues 8,567 3,913 119 %
Natural gas liquids revenues 15,601 15,424 1 %
Total revenues $ 144,523 $ 191,262 (24) %
Lease operating expense $ 29,131 $ 28,683 2 %
Production and ad valorem taxes $ 9,411 $ 11,871 (21) %
Impairment expense $ 64,498 $ - NM
Depreciation, depletion and amortization $ 96,414 $ 69,243 39 %
General and administrative expense (excluding stock-based compensation) $ 18,179 $ 18,963 (4) %
Stock-based compensation $ 10,054 $ 8,648 16 %
General and administrative expense $ 28,233 $ 27,611 2 %
Transaction costs $ 622 $ 1,077 (42) %
Gain on sale of oil and gas properties, net $ 204 $ 3,222 (94) %
Interest expense, net $ (5,232) $ (6,566) (20) %
Write-off of deferred financing costs $ - $ (1,242) NM
Unrealized gain (loss) on derivative contracts $ 3,855 $ (59,849) (106) %
Realized gain on derivative contracts $ 56,044 $ 15,866 253 %
Gain (loss) on derivative contracts, net $ 59,899 $ (43,983) (236) %
Income tax benefit (expense) $ 112 $ (1,665) (107) %
(1)Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equals one barrel of oil equivalent (BOE).
NM - Not meaningful
Oil revenues
For the year ended December 31, 2020, oil revenues decreased by approximately $51.6 million or 30% compared to 2019. Of the decrease, $55.1 million was attributable to lower realized prices, partially offset by $3.5 million due to increased sales volumes. Our average realized price per Bbl decreased from $55.71 for the year ended December 31, 2019 to $37.85 or 32% for the year ended December 31, 2020. We had a net increase in the volume of oil sold of 93 MBbls or 3%, primarily due to new wells brought online offset by production shut-ins we initiated in May 2020 due to the domestic collapse of oil prices.
Natural gas revenues
For the year ended December 31, 2020, natural gas revenues increased by $4.7 million or 119% compared to 2019. Of the increase, $3.0 million was attributable to increased sales volumes and $1.7 million was due to higher realized prices. Our average realized price per Mcf increased 43% from $0.82 for the year ended December 31, 2019 to $1.18 for the year ended December 31, 2020. In the prior year, lack of sufficient pipeline transportation resulted in low natural gas prices, which improved in 2020. The total volume of natural gas produced and sold increased 2,522 MMcf or 53% primarily due to new wells brought online offset by the production shut-ins we initiated in May 2020.
Natural gas liquids revenues
For the year ended December 31, 2020, natural gas liquids revenues were relatively flat as compared to 2019 as a $2.3 million increase attributable to higher sales volumes was mostly offset by a $2.1 million decrease due to lower realized prices. The volume of natural gas liquids produced and sold increased by 176 MBbls or 17%, primarily due to new wells brought online offset by voluntary production shut-ins in May 2020.
Lease operating expense (“LOE”)
LOE includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, re-engineering and workovers, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance and overhead charges provided for in operating agreements.
LOE remained relatively flat, increasing by $0.4 million or 2% for the year ended December 31, 2020 compared to 2019, primarily due to costs reduction efforts implemented during 2020, offset by increased production in 2020.
Production and ad valorem taxes
Production and ad valorem taxes for the year ended December 31, 2020 decreased by $2.5 million or 21% compared to 2019, as the impact of increased volume was more than offset by the impact of decreased commodity prices. As a percentage of revenues from oil, natural gas, and natural gas liquids, production taxes remained relatively flat in 2020 compared to the prior year.
Impairment
During the year ended December 31, 2020, we recorded non-cash impairments totaling $64.5 million which consisted of $25.3 million to proved oil and natural gas properties, $21.6 million to unproved oil and natural gas properties and $17.6 million to goodwill. No impairments were recorded during the year ended December 31, 2019. See Note 7. Oil and Natural Gas Properties in the Notes to Consolidated Financial Statements for a discussion of how impairments are measured.
Depreciation, depletion and amortization (“DD&A”)
DD&A increased for the year ended December 31, 2020 by $27.2 million, or 39% compared to 2019, primarily due to reserve reductions resulting from depressed commodity prices (lower reserve quantities leads to higher DD&A per Boe), partially offset by a first quarter 2020 impairment charge of $25.3 million which resulted in a decreased depletable oil and natural gas properties base.
General and administrative expense (“G&A”)
These expenses consist primarily of employee remuneration, professional and consulting fees and other overhead expenses. G&A increased by $0.6 million for the year ended December 31, 2020 relative to the comparable period in 2019, primarily due to a $1.4 million increase in non-cash stock-based compensation expense related to awards granted in January 2020, offset by $0.8 million in reductions in cash-based expenses resulting from cost reduction efforts implemented in 2020.
Transaction costs
During the year ended December 31, 2020, we recorded transaction costs primarily due to legal, consulting and other fees of approximately $1.0 million related to the business combination which was consummated on January 7, 2021 and $0.3 million related to other potential transactions, offset by net reimbursements of $0.7 million related to the business combination (the “Bold Transaction”) pursuant to the Bold Contribution Agreement (as defined below) which closed on May 9, 2017. During the year ended December 31, 2019, the Company recorded transaction costs totaling approximately $1.1 million primarily due to the Bold Transaction.
Gain on sale of oil and gas properties, net
During the years ended December 31, 2020 and 2019, we sold certain oil and gas properties located in the Midland Basin, recording gains totaling $0.2 million and $3.6 million, respectively. See Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.
Interest expense, net
Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense decreased from $6.6 million for the year ended December 31, 2019, to $5.2 million for the year ended December 31, 2020 primarily due to lower effective interest rates, as well as lower outstanding borrowings compared to the prior year. See Note 13. Long-Term Debt in the Notes to Consolidated Financial Statements.
Write-off of deferred financing costs
During the year ended December 31, 2019, in connection with the termination of the prior credit agreement, $1.2 million of remaining unamortized deferred financing costs were expensed and included in Write-off of deferred financing costs in the Consolidated Statements of Operations. See Note 13. Long-Term Debt in the Notes to Consolidated Financial Statements.
Gain (loss) on derivative contracts, net
For the year ended December 31, 2020, we recorded a net gain on derivative contracts of $59.9 million, consisting of net realized gains on settlements of $56.0 million and unrealized mark-to-market gains of $3.9 million. For the year ended December 31, 2019, we recorded a net loss on derivative contracts of $44.0 million, consisting of unrealized mark-to-market losses of $59.8 million, partially offset by net realized gains on settlements of $15.9 million.
Income tax benefit (expense)
During the year ended December 31, 2020, the Company recorded total income tax benefit of $0.11 million which included (1) deferred income tax expense for Lynden US of $0.15 million as a result of its share of the distributable income from EEH, (2) deferred income tax benefit for Earthstone of $0.61 million as a result of its share of the distributable loss from EEH, which was offset by a valuation allowance as future realization of the net deferred tax asset cannot be assured and (3) current income tax expense of $0.55 million, offset by deferred income tax benefit of $0.51 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2020.
During the year ended December 31, 2019, the Company recorded a total income tax expense of $1.7 million which included (1) deferred income tax expense for Lynden US of $0.1 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $0.4 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $1.6 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2019.
Liquidity and Capital Resources
We have significant undeveloped acreage and future drilling locations. Drilling horizontal wells, generally consisting of 7,500 to 12,000-foot lateral lengths, in the Midland Basin is capital intensive. As of December 31, 2020, we had $1.5 million in cash and $115 million of long-term debt outstanding under our Credit Agreement with a borrowing base of $240 million. With the $125 million of undrawn borrowing base capacity and $1.5 million in cash, we had total liquidity of approximately $126.5 million. Subsequent to year-end, Earthstone closed on its previously announced acquisition of IRM and amended the Credit Agreement. As of March 1, 2021, we had $10.1 million in cash and $227.5 million of long-term debt outstanding under our Credit Agreement, as amended, with a borrowing base of $360 million. With the $132.5 million of undrawn borrowing base capacity and $10.1 million in cash, we had total liquidity of approximately $142.6 million.
As oil prices have recovered recently from their 2020 lows, we are preparing to resume drilling operations with the deployment of a rig late in the first quarter of 2021 and we expect to spend $90-$100 million based on our current 2021 drilling plan. We believe we will have sufficient liquidity with cash flows from operations and borrowings under the Credit Agreement to meet our cash requirements for the next 12 months.
Working Capital
Working Capital (presented below) was a deficit of $20.8 million as of December 31, 2020 compared to a deficit of $39.9 million as of December 31, 2019, representing an improvement of $19.2 million. The improvement was primarily due to the reduction of liabilities resulting from reduced drilling activity. The components of working capital are presented below:
December 31,
2020 2019
Current assets:
Cash $ 1,494 $ 13,822
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues 16,255 29,047
Joint interest billings and other, net of allowance of $19 and $83 at December 31, 2020 and 2019, respectively 7,966 6,672
Derivative asset 7,509 8,860
Prepaid expenses and other current assets 1,509 1,867
Total current assets 34,733 60,268
Current liabilities:
Accounts payable $ 6,232 $ 25,284
Revenues and royalties payable 27,492 35,815
Accrued expenses 16,504 19,538
Asset retirement obligation 447 308
Derivative liability 1,135 6,889
Advances 2,277 11,505
Operating lease liability 773 570
Finance lease liability 69 206
Other current liabilities 565 43
Total current liabilities 55,494 100,158
Working Capital $ (20,761) $ (39,890)
We expect that changes in receivables and payables related to our pace of development, production volumes, changes in our hedging activities, realized commodity prices and differentials to NYMEX prices for our oil and natural gas production will continue to be the largest variables affecting our working capital.
We expect to finance future development activities with cash flows from operating activities, borrowings under the Credit Agreement and, various means of corporate and project financing. Additionally, we may continue to partially finance our drilling activities through the sale of participating rights to financial institutions or industry participants, and we could structure such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate share of capital costs.
In July 2019, we entered into a Wellbore Development Agreement (“WDA”) with a non-affiliated industry partner. This WDA reduced our working interest in certain wells in Reagan County. The industry partner paid a promoted (proportionately higher) share of the capital expenditures on eight wells, to earn 35% of the working interest in these wells.
Capital Expenditures
Our accrual basis capital expenditures for the years ended December 31, 2020 and 2019 were as follows:
Years Ended December 31,
(In thousands)
2020 2019
Drilling and completions $ 66,580 $ 202,332
Leasehold costs 208 8,098
Total capital expenditures $ 66,788 $ 210,430
Hedging Activities
The following table sets forth our outstanding derivative contracts at December 31, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.
Period Commodity Volume
(Bbls / MMBtu) Price
($/Bbl / $/MMBtu)
2021 Crude Oil Swap 2,294,000 $51.17
2021 Crude Oil Basis Swap (1) 1,825,000 $1.05
2022 Crude Oil Swap 365,000 $47.70
2021 Natural Gas Swap 4,380,000 $2.76
2021 Natural Gas Basis Swap (2) 4,380,000 $(0.45)
(1)The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX.
(2)The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
On January 7, 2021, upon closing of the IRM Acquisition, IRM had hedges in place for approximately 1,008,950 Bbls of oil at $41.07/Bbl.
Hedging Update
The following table sets forth our outstanding derivative contracts at March 4, 2021. When aggregating multiple contracts, the weighted average contract price is disclosed.
Period Commodity Volume
(Bbls / MMBtu) Price
($/Bbl / $/MMBtu)
2021 Crude Oil Swap 3,326,750 $48.04
2021 Crude Oil Basis Swap (1) 2,857,750 $0.79
2021 Crude Oil Basis Swap (2) 1,032,750 $(0.26)
2022 Crude Oil Swap 1,458,500 $52.96
2022 Crude Oil Basis Swap (1) 1,368,750 $0.74
2021 Natural Gas Swap 6,912,000 $2.81
2021 Natural Gas Basis Swap (3) 6,912,000 $(0.37)
Q1 2022 Natural Gas Swap 450,000 $2.97
Q1 2022 Natural Gas Basis Swap (3) 450,000 $(0.23)
(1) The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX.
(2) The swap is between WTI Roll and the WTI NYMEX.
(3) The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
Obligations and Commitments
We had the following contractual obligations and commitments as of December 31, 2020:
(In thousands) 2021 2022 2023 2024 2025 Thereafter
Debt (1)
$ 349 $ - $ - $ 115,000 $ - $ -
Derivative liabilities 1,135 173 - - - -
Asset retirement obligations 447 125 364 - - 2,091
Gas contracts (2)
680 - - - - -
Office leases 791 696 595 605 152 -
Automobile leases 75 5 - - - -
Total $ 3,477 $ 999 $ 959 $ 115,605 $ 152 $ 2,091
(1)2021 amount represents interest payable under the Credit Agreement as of December 31, 2020.
(2)We have a non-cancelable fixed cost agreement of $0.7 million per year through May 2021 to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing related to certain Eagle Ford assets in south Texas. As the operator of the properties dedicated to this contract, the gross amount of obligation is provided; however, our net share is approximately 31%.
On January 7, 2021, upon closing of the IRM Acquisition, EEH became party to an office lease with an effective termination date of May 31, 2021, for which the remaining obligation is approximately $0.26 million.
Environmental Regulations
Our operations are subject to risks normally associated with the exploration for and the production of oil and natural gas, including blowouts, fires, and environmental risks such as oil spills or natural gas leaks that could expose us to liabilities associated with these risks.
In our acquisition of existing or previously drilled well bores, we may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. We maintain comprehensive insurance coverage that we believe is adequate to mitigate the risk of any adverse financial effects associated with these risks.
However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still accrue to us. No claim has been made, nor are we aware of any liability which we may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other risks. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Oil and Natural Gas Properties
We use the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire oil and natural gas properties, drill successful exploratory wells, drill and equip development wells, and install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells, geological and geophysical are charged to operations as incurred. Depreciation, depletion and amortization of the leasehold and development costs that are capitalized for proved oil and natural gas properties are computed using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers. Oil and natural gas properties are periodically assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group, but at least annually. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. All of our properties are located within the continental United States.
Oil and Natural Gas Reserve Quantities
Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion, impairment of our oil and natural gas properties, and asset retirement obligations. Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”). The accuracy of our reserve estimates is a function of:
•The quality and quantity of available data;
•The interpretation of that data;
•The accuracy of various mandated economic assumptions; and
•The judgments of the persons preparing the estimates.
Our proved reserves information included in this report is based on estimates prepared by our independent petroleum engineers, CG&A. The independent petroleum engineers evaluated 100% of our estimated proved reserve quantities and their related future net cash flows as of December 31, 2020. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates, impairment calculations, and asset retirement obligations in the same period that changes to reserve estimates are made.
Depreciation, Depletion and Amortization
Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.
Impairment of Oil and Natural Gas Properties
We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing the pretax future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined based on expected future cash flows using discount rates commensurate with the risks involved, using prices and costs consistent with those used for internal decision making. Different pricing assumptions or discount rates could result in a different calculated impairment. We provide for impairments on significant undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.
Asset Retirement Obligation
Our asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the field.
Derivative Instruments and Hedging Activity
We are exposed to certain risks relating to our ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We follow FASB Accounting Standards Codification (“ASC”)
Topic 815, Derivatives and Hedging, to account for our derivative financial instruments. We do not enter into derivative contracts for speculative trading purposes. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. We did not post collateral under any of these contracts.
Our crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that we receive or make payments based on a differential between fixed and variable prices for crude oil and natural gas. We have elected to not designate any of our derivative contracts for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “(Loss) gain on derivative contracts, net” on the Consolidated Statements of Operations. All derivative contracts are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities.
Income Taxes and Uncertain Tax Positions
We are a U.S. company operating in Texas, as of December 31, 2020, as well as one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, our tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which our operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, we are required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in different taxing jurisdictions.
Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from Earthstone’s acquisition of Lynden Corp in 2016 (the “Lynden Arrangement”) that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.
On January 7, 2021, upon closing of the IRM Acquisition, the acquired entity, Independence Resources Management, LLC (along with its wholly owned subsidiaries, collectively “IRM”), became a wholly owned subsidiary of EEH. IRM’s results will be reported on the U.S. Return of Partnership Income (Form 1065) and will flow to EEH through Schedule K-1 (Form 1065). As IRM is treated as a Partnership, for federal and state income tax purposes, it is not subject to income taxes at the federal level. At the state level, IRM only operates in Texas and is subject to the Texas Margin Tax.
Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in our Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2020 and 2019, we recorded a valuation allowance for our deferred tax assets in the Consolidated Balance Sheets.
We apply the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that we recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. Our tax positions related to our pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by our management and they believe those positions would more likely than not be sustained upon examination. Accordingly, we have not recorded an income tax liability for uncertain tax positions at December 31, 2020 or 2019.
Revenue Recognition
We predominantly derive our revenue from the sale of produced oil, natural gas and natural gas liquids. Revenues are recognized when the recognition criteria of FASB ASC Topic 606, Revenue from Contracts with Customers, are met, which generally occurs at the point in which title passes to the customers. We receive payment from one to three months after delivery. At the end of each quarter, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant.
Accounting for Business Combinations
Our business has grown substantially through acquisitions, and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations to date using the purchase method.
Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given. The assets and liabilities acquired are measured at their fair value including the recognition of acquisition-related costs that are separate from the acquired net assets. The purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, and comparison to transactions for similar assets and liabilities, and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.
Goodwill
We account for goodwill in accordance with FASB ASC Topic 350, Intangibles - Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of the liabilities assumed in an acquisition. ASC Topic 350 requires that goodwill be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in an impairment.
We conduct a qualitative goodwill impairment assessment by examining relevant events and circumstances which could have a negative impact on our goodwill such as, industry and market conditions, including commodity prices, costs factors, and other company specific events. If we conclude that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then we do not have to perform the two-step impairment test. If after assessing the totality of events or circumstances described, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If, after performing the two-step goodwill test, it is determined that the carrying value of goodwill is impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired
Noncontrolling Interest
We account for noncontrolling interest in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of Net (loss) income, as well as a noncontrolling interest component within equity. Noncontrolling interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2020 and 2019, as well as an adjustment to Net (loss) income in the Consolidated Statement of Operations for the years ended December 31, 2020 and 2019.
As of December 31, 2020, Earthstone and Lynden US held 46.4% of the outstanding membership interests in EEH while Bold Holdings, the noncontrolling party, held the remaining 53.6%. See further discussion in Note 9. Noncontrolling Interest in the Notes to Consolidated Financial Statements.
Recently Issued Accounting Standards
See Note 2. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this report for a discussion of recently issued accounting standards affecting us.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and therefore are not required to provide the information required under this item.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
See Index to Consolidated Financial Statements and Supplementary Information on Page.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Internal Control Over Financial Reporting
Evaluation of Disclosure Controls and Procedures
(a) Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
In accordance with Rules 13a-15(b) and 15d-15(b) under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer, of the effectiveness of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. As described below under paragraph (b) within Management’s Annual Report on Internal Control over Financial Reporting, our Chief Executive Officer and Principal Accounting Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
The audit report of our independent registered public accounting firm, which is included in this Annual Report on Form 10-K, expressed an unqualified opinion on our consolidated financial statements.
(b) Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is 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. Our internal control over financial reporting includes those policies and procedures that:
•pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management; and
•provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
While “reasonable assurance” is a high level of assurance, it does not mean absolute assurance. Because of its inherent limitations, internal control over financial reporting may not prevent or detect every misstatement and instance of fraud. Controls are susceptible to manipulation, especially in instances of fraud caused by collusion of two or more people. 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.
Under the supervision and with the participation of our Chief Executive Officer and Principal Accounting Officer, our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020. In making this evaluation, management used the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the results of our evaluation, our management concluded that our internal control over financial reporting was effective, at the reasonable assurance level, as of December 31, 2020.
Our independent registered public accounting firm that audited our consolidated financial statements, has also issued its own audit report on the effectiveness of our internal control over financial reporting as of December 31, 2020, which is included herein.
(c) Changes in Internal Control over Financial Reporting
There have not been any changes in our internal control over financial reporting during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of
Earthstone Energy, Inc.
Opinion on Internal Control over Financial Reporting
We have audited Earthstone Energy, Inc. and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of Earthstone Energy, Inc. and subsidiaries as of December 31, 2020 and 2019, the related consolidated statements of operations, equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated March 10, 2021 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 Report on Internal Control over Financial Reporting included in Item 9A. 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 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/ Moss Adams LLP
Houston, Texas
March 10, 2021
We have served as the Company’s auditor since 2018.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
See list of “Information about our Executive Officers” under Item 1 of this report, which is incorporated herein by reference.
The other information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibit and Financial Statement Schedules
Incorporated by Reference
Exhibit
No. Description Form SEC File No. Exhibit Filing Date Filed
Herewith Furnished
Herewith
2.1 Contribution Agreement dated November 7, 2016, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Lynden USA Inc., Lynden USA Operating, LLC, Bold Energy Holdings, LLC and Bold Energy III LLC.
8-K 001-35049 2.1 November 8, 2016
2.1(a) First Amendment to the Contribution Agreement dated March 21, 2017, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Lynden USA Inc., Lynden USA Operating, LLC, Bold Energy Holdings, LLC and Bold Energy III LLC.
8-K 001-35049 2.1 March 23, 2017
2.2 Purchase and Sale Agreement dated as of December 17, 2020, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Independence Resources Holdings, LLC and Independence Resources Manager, LLC
8-K 001-35049 2.1 December 22, 2020
3.1 Third Amended and Restated Certificate of Incorporation of Earthstone Energy, Inc. dated May 9, 2017.
8-A 001-35049 3.1 May 9, 2017
3.2 Amended and Restated Bylaws of Earthstone Energy, Inc. dated February 26, 2010.
8-K 001-35049 3(ii) March 3, 2010
3.2(a) First Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated November 22, 2011.
8-K 001-35049 3(ii)c November 23, 2011
3.2(b) Second Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated October 22, 2015.
8-K 001-35049 3.2 October 26, 2015
4.1 Specimen Class A Common Stock Certificate of Earthstone Energy, Inc.
8-K 001-35049 4.1 May 15, 2017
4.2 Description of Earthstone Energy, Inc.’s Class A Common Stock.
10-K 001-35049 4.2 March 11, 2020
10.1† Earthstone Energy, Inc. 2014 Long-Term Incentive Plan.
8-K 001-35049 10.3 December 29, 2014
10.1(a)† First Amendment to the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan dated October 22, 2015.
8-K 001-35049 10.1 October 26, 2015
10.1(b)† Second Amendment to the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan dated May 9, 2017.
8-K 001-35049 10.6 May 15, 2017
10.2 Form of Indemnification Agreement.
8-K 001-35049 10.5 December 29, 2014
10.3† Form of Restricted Stock Unit Agreement (Executive Management).
8-K 001-35049 10.1 June 2, 2016
10.4† Form of Restricted Stock Unit Agreement (Employee).
8-K 001-35049 10.2 June 2, 2016
10.5 First Amended and Restated Limited Liability Company Agreement of Earthstone Energy Holdings, LLC dated May 9, 2017.
8-K 001-35049 10.1 May 15, 2017
10.6 Registration Rights Agreement dated May 9, 2017 between Earthstone Energy, Inc. and Bold Energy Holdings, LLC.
8-K 001-35049 10.3 May 15, 2017
10.7 Voting Agreement dated May 9, 2017 by and among Earthstone Energy, Inc., EnCap Investments L.P., Oak Valley Resources, LLC and Bold Energy Holdings, LLC.
8-K 001-35049 10.4 May 15, 2017
10.7(a) First Amendment to the Voting Agreement dated April 22, 2020, by and among Earthstone Energy, Inc., EnCap Investments L.P., and Bold Energy Holdings, LLC
8-K 001-35049 10.1 April 24, 2020
10.8† Performance Unit Award Agreement (Executive Management).
8-K 001-35049 10.2 March 2, 2018
10.9† Amended and Restated 2014 Long Term Incentive Plan dated June 6, 2018.
8-K 001-35049 10.1 June 6, 2018
10.9(a) First Amendment to the Earthstone Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan dated June 3, 2020.
8-K 001-35049 10.1 June 5, 2020
10.10† Form of Performance Unit Agreement (Executive Management).
8-K 001-35049 10.2 February 1, 2019
10.11† Earthstone Energy, Inc. Amended and Restated Change in Control and Severance Benefit Plan.
8-K 001-35049 10.1 January 29, 2021
10.12 Credit Agreement dated November 21, 2019, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association as Administrative Agent and Issuing Bank, BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, SunTrust Bank, as Documentation Agent, and the Lenders party thereto.
8-K 001-35049 10.1 November 22, 2019
10.12(a) First Amendment to Credit Agreement dated September 28, 2020, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, the Guarantors party thereto, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders party thereto
8-K 001-35049 10.1 October 1, 2020
10.12(b) Second Amendment to Credit Agreement dated December 17, 2020, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, the Guarantors party thereto, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders party thereto
8-K 001-35049 10.1 December 22, 2020
10.13† Form of Performance Unit Agreement (Executive Management).
8-K 001-35049 10.1 January 31, 2020
10.14† Form of Restricted Stock Unit Agreement (Executive Management).
8-K 001-35049 10.2 January 31, 2020
10.15† Form of Restricted Stock Unit Agreement (Director).
8-K 001-35049 10.3 January 31, 2020
10.16 Registration Rights Agreement dated January 7, 2021, by and among Earthstone Energy, Inc., Independence Resources Holdings, LLC and the Persons identified on Schedule I thereto
8-K 001-35049 10.1 January 13, 2021
10.17 Voting Agreement dated January 7, 2021, by and among Earthstone Energy, Inc., EnCap Investments L.P., Warburg Pincus Private Equity (E&P) XI - A, L.P., Warburg Pincus XI (E&P) Partners - A, L.P., WP IRH Holdings, L.P., Warburg Pincus XI (E&P) Partners - B IRH, LLC, Warburg Pincus Energy (E&P)-A, LP, Warburg Pincus Energy (E&P) Partners-A, LP, Warburg Pincus Energy (E&P) Partners-B IRH, LLC, WP Energy Partners IRH Holdings, L.P., and WP Energy IRH Holdings, L.P.
8-K 001-35049 10.2 January 13, 2021
10.18 Lock-up Agreement dated January 7, 2021, by and among Earthstone Energy, Inc., Warburg Pincus Private Equity (E&P) XI - A, L.P., Warburg Pincus XI (E&P) Partners - A, L.P., WP IRH Holdings, L.P., Warburg Pincus XI (E&P) Partners - B IRH, LLC, Warburg Pincus Energy (E&P)-A, LP, Warburg Pincus Energy (E&P) Partners-A, LP, Warburg Pincus Energy (E&P) Partners-B IRH, LLC, WP Energy Partners IRH Holdings, L.P., and WP Energy IRH Holdings, L.P.
8-K 001-35049 10.3 January 13, 2021
10.19† Form of Performance Unit Agreement (Executive Management).
8-K 001-35049 10.1 January 29, 2021
14.1 Code of Business Conduct and Ethics.
8-K 001-35049 14 January 13, 2021
21.1 List of Subsidiaries.
X
23.1 Consent of Cawley, Gillespie & Associates, Inc.
X
23.2 Consent of Moss Adams LLP.
X
31.1 Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
X
31.2 Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
X
32.1 Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.
X
32.2 Certification of the Executive Vice President - Accounting and Administration pursuant to Section 906 of the Sarbanes-Oxley Act.
X
99.1 Report of Cawley, Gillespie & Associates, Inc.
X
101.INS XBRL Instance Document. X
101.SCH XBRL Schema Document. X
101.CAL XBRL Calculation Linkbase Document. X
101.DEF XBRL Definition Linkbase Document. X
101.LAB XBRL Label Linkbase Document. X
101.PRE XBRL Presentation Linkbase Document. X
104 Cover Page Interactive Data File (embedded within the Inline XBRL document). X
† Indicates management contract or compensatory plan or arrangement.